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Home My WebLink About225-084 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-040 (50-103-20924-0000) Final Well data Submittal - Details on following pages. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 12/4/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 225-084 T41174 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.12.05 10:24:09 -09'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDB-040 Comparison view 1.pdf ؒ NDB-040 Comparison view 2.pdf ؒ NDB-040 Definitive Compass Survey Report - NAD27.pdf ؒ NDB-040 Definitive Compass Survey Report - NAD83.pdf ؒ NDB-040 Definitive Survey - NAD27.txt ؒ NDB-040 Definitive Survey - NAD83.txt ؒ NDB-040 Definitive Survey Report.xlsx ؒ NDB-040 Plan View.pdf ؒ NDB-040 Vertical Section.pdf ؒ ؤؐؐؐLog Digital Data and Plots ؤؐؐؐLWD جؐؐؐDigital Data ؒ جؐؐؐFE ؒ ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871-15021ft.las ؒ ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft.las ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-040_AP_R01_RM.las ؒ ؒ NDB-040_AP_R02_RM.las ؒ ؒ NDB-040_AP_R03_RM.las ؒ ؒ NDB-040_AP_R04_RM.las ؒ ؒ NDB-040_AP_R05_RM.las ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-040_DMD_RM_22871ft.las ؒ NDB-040_DMT_R01_RM.las ؒ NDB-040_DMT_R02_RM.las ؒ NDB-040_DMT_R03_RM.las ؒ NDB-040_DMT_R04_RM.las ؒ NDB-040_DMT_R05_RM.las ؒ جؐؐؐGeoscience Deliverables ؒ جؐؐؐ7in TOC ؒ ؒ NBD-040_TOC-RM_11300-14926ft_1000.Pdf ؒ ؒ NBD-040_TOC-RM_11300-14926ft_200.Pdf ؒ ؒ NBD-040_TOC-RM_11300-14926ft_2000.Pdf ؒ ؒ NBD-040_TOC-RM_11300-14926ft_4000.Pdf ؒ ؒ NBD-040_TOC-RM_11300-14926ft_4000_Labeled.Pdf ؒ ؒ NBD-040_TOC-RM_11300-14926ft_500.Pdf ؒ ؒ NBD-040_TOC-RM_11300-14926ft_6000.Pdf LETTER OF TRANSMITTAL ؒ ؒ NDB-040_7in_Liner_TOC.pdf ؒ ؒ NDB-040_R5_7in_Liner_SonicScope475_ReamDown_RM_TOC_PPT.pptx ؒ ؒ NDB-040_TOC-RM_DLIS_11300-14926ft MD.dlis ؒ ؒ NDB-040_TOC-RM_DLIS_11300-14926ft MD_DLIS Verification.html ؒ ؒ ؒ ؤؐؐؐSoundTrak Acoustic Data ؒ NBD-040_SDTK_DTC_9987-14912.5_RUN4.cgm ؒ NBD-040_SDTK_DTC_9987-14912.5_RUN4.las ؒ NBD-040_SDTK_DTC_9987-14912.5_RUN4.PDF ؒ NBD-040_SDTK_DTC_DTS_9987-14912.5_RUN4.cgm ؒ NBD-040_SDTK_DTC_DTS_9987-14912.5_RUN4.dlis ؒ NBD-040_SDTK_DTC_DTS_9987-14912.5_RUN4.las ؒ NBD-040_SDTK_DTC_DTS_9987-14912.5_RUN4.PDF ؒ NBD-040_SDTK_DTC_DTS_9987-14912.5_RUN4.txt ؒ NBD-040_SDTK_WIDEBED_9987-14912.5_RUN4.cgm ؒ NBD-040_SDTK_WIDEBED_9987-14912.5_RUN4.PDF ؒ ؤؐؐؐGraphic Images جؐؐؐCGM ؒ جؐؐؐFE ؒ ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871-15021ft_BROOH.cgm ؒ ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_2MD.cgm ؒ ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_2TVD.cgm ؒ ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_5MD.cgm ؒ ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_5TVD.cgm ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-040_AP_RM.cgm ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-040_DMD_RM_22871ft.cgm ؒ NDB-040_DMT_RM.cgm ؒ ؤؐؐؐPDF جؐؐؐFE ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871-15021ft_BROOH.pdf ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_2MD.pdf ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_2TVD.pdf ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_5MD.pdf ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_5TVD.pdf ؒ جؐؐؐPWD LETTER OF TRANSMITTAL ؒ NDB-040_AP_RM.pdf ؒ ؤؐؐؐVSS NDB-040_DMD_RM_22871ft.pdf NDB-040_DMT_RM.pdf LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-040 (50-103-20924-0000) Frac Sundry requested data – details on following page Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 11/6/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 225-084 T41065 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.06 08:27:42 -09'00' LETTER OF TRANSMITTAL جؐؐؐAdditional Data ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_2MD.pdf ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_2TVD.pdf ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_5MD.pdf ؒ NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft_5TVD.pdf ؒ NDB-040_MWD_R05_22871ft_Survey.csv ؒ NDB-040_MWD_R05_22871ft_Survey.PDF ؒ NDB-040_MWD_R05_22871ft_Survey.txt ؒ ؤؐؐؐKey Data NDB-040 Fm.xlsx NDB-040_LWD_GR_Res_Den_Neu_Cal_RM_22871ft.las NDB-040_MWD_R05_22871ft_Survey.xlsx 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Well Clean Up 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 22,871' N/A Casing Collapse Conductor Surface 2,260 Intermediate 4,750 Tieback 4,750 Intermediate 2 5,410 Production 9,210 Liner 9,210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:scott.leahy@santos.com Contact Phone: 907-330-4595 Authorized Title: Completions Specialist Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. 14,921 Perforation Depth MD (ft): 9,995 5,071 4-1/2" 22,8548,139 4-1/2" 12.6ppf 4,1117" 20"x34" 13-3/8" 128' 9-5/8"7,128 3,058 3,279 2,309 MD 6,870 5,020 128 2,389 128 3,058 Length Size Proposed Pools: P110S TVD Burst 14,715 7,240 Pikka Nanushuk Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 391445, 393023, 393022, 392977, 392958 225-084 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20924-00-00 Oil Search Alaska, LLC Pikka NDB-040 AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): See attached packer report Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Leahy 14,715 4-1/2" 14,715 4,066 11,590 11/20/2025 4,09 See attached packer report N/A 2,800 Tieback 2,800 6,870 4,093 22,852 4,09 P ell Cla Well Stat oposed wor dedd t edeeedeedn C t P W No Comm.Form 10-403 Revised 06/2023 Sr Pet Eng Approved application valid Sr Pet Geo for 12 months from date of approval.o a Sr Rogescc.EnpergSubmit PDF t mitting@alaska.gov e foregoing is true and the 11/04/2025 325-680 By Grace Christianson at 7:52 am, Nov 05, 2025 DSR-11/6/25 11/20/2025 CDW 11/05/2025 A.Dewhurst 11NOV25 BJM 11/11/25 10-404 JLC 11/12/2025 11/12/25 Item Description Top (ftKB)Top (TVD) (ft KB) ZXP Liner Top Hanger Packer W/HRD-E Profile 14,715 4,060 HES Zoneguard OH Packer #16 14,999 4,125 HES Zoneguard OH Packer #15 15,064 4,140 HES Zoneguard OH Packer #14 15,609 4,165 HES Zoneguard OH Packer #13 16,071 4,160 HES Zoneguard OH Packer #12 16,739 4,154 HES Zoneguard OH Packer #11 17,282 4,150 HES Zoneguard OH Packer #10 17,866 4,144 HES Zoneguard OH Packer #9 18,410 4,138 HES Zoneguard OH Packer #8 18,956 4,132 HES Zoneguard OH Packer #7 19,543 4,127 HES Zoneguard OH Packer #6 20,082 4,122 HES Zoneguard OH Packer #5 20,665 4,116 HES Zoneguard OH Packer #4 21,210 4,111 HES Zoneguard OH Packer #3 21,796 4,105 HES Zoneguard OH Packer #2 22,341 4,099 HES Zoneguard OH Packer #1 22,719 4,095 Packer Set Depths - NDB-040 Page 1 of 20 NDB-040 Sundry Application Requirements 1. Affidavit of Notice Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius Attachment B 3. Identification of freshwater aquifers within ½ mile radius There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBD-040. At the NDB-040 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifer (typically found down to 400 ft depth) are located at the NDB-040 location. 4. Plan for freshwater sampling There are no known freshwater wells in the proximity to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information Attachment C 6. Assessment of casing and cementing operations Attachment C 7. Casing and tubing pressure test information Attachment D 8. Pressure ratings for wellbore, wellhead, BOPE and treating head Attachments D and I 9. Lithological and geological descriptions of each zone Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 965 feet (ft) total vertical depth subsea (TVDSS)/ 965 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 965 to 2,387 ft TVDSS/1,422 ft thick Lithological Description: The Schrader Bluff Fm in the Pikka Unit area was deposited in a shallow marine to shelf setting and dominantly consists of light grey claystone in the Upper Schrader Bluff (including shell fragments, lignite, and cherts), grading to a dark mudstone in the Middle Schrader and grading to a massive blocky shale in the Lower Schrader Bluff. Interbedded volcanic ash was observed and increasing from the Lower Schrader Bluff Fm. There are some thin (<15 ft), poor-quality (high clay content, low permeability) sands present in the Upper Schrader Bluff Fm within the Pikka Unit. Tuluvak Formation Depth/Thickness: 2,387 to 3,289 ft TVDSS/ 902 ft thick Hydrocarbon Zone: 2,756 to 3,289 ft TVDSS Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Upper Confining Zone Name Seabee Formation Depth/Thickness: 3,289 to 3,736 ft TVDSS/ 447 ft thick Lithological Description: The Seabee Fm in the Pikka Unit area consists predominantly of claystone, shale, and volcanic tuff deposited in a deep marine setting. The base of the Seabee Fm grades into a condensed organic shale and provides an excellent seal and confining interval above the Nanushuk Fm reservoirs and also acts as a thick second overlying confining unit. Nanushuk Formation Depth/Thickness: 3,737 to 4,691 ft TVDSS/ 954 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east. The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Lower Confining Zone Name: Torok Formation Depth/Thickness: 4,691 to 5,590 ft TVDSS/899 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is composed primarily of shale (Hue Shale) with some thin interbedded siltstones. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. 10.Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Surface Line Pressure Test (psi) MAWP (psi) Stages 1-14 3,800 4,100 8,500 8,100 9,200 8,800 Note: GORV and pump trips to be set to 8700 psi to open Toe Sleeve Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft Mechanical condition of wells transecting the confining zones NDBi-049, NDBi- 036, NDBi-050, NDBi-050PB1 NDB-048, and NDBi-046/NDBi-046L1. Please see Attachment B as reference. Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 22,613 4,096 239 498 40 6,604 8 2 22,070 4,102 241 499 40 6,564 8 3 21,483 4,108 244 521 40 6,899 10 4 20,937 4,113 250 422 40 6,695 10 5 20,395 4,118 249 420 40 6,545 10 6 19,816 4,124 248 414 40 6,381 10 7 19,271 4,129 245 387 40 6,485 11 8 18,684 4,135 247 406 40 6,595 12 9 18,055 4,141 245 387 40 6,112 11 10 17,554 4,146 250 414 45 7,313 12 11 17,012 4,151 251 430 45 7,141 12 12 16,466 4,157 251 440 45 6,313 10 13 15,882 4,164 252 450 45 6,127 10 14 15,296 4,162 248 410 45 5,934 10 7,313 A cross-section map of NDB-040 is presented in Attachment B. NDBi-050 is shown to sail over NDB-040 by approximately 112 feet. Per the fracture model for Stages 12-14 on NDB-040, the stages closest in proximity to the lateral of NDBi- 050, the fracture height growth is approximately 85-90 feet above the lateral where the fracture is initiated and would not intersect the NDBi-050 wellbore. Additionally, the NDB-040 lateral is 708 feet away from NDB-048 when considering the 330-degree plane that both wells have the lateral drilled. Note that the induced fractures are thought to propagate at 330 degrees which would provide sufficient offset given that the modelled half length is estimated at 410 feet for Stage 14 on NDB-040. Santos will monitor the BHP on wells NDBi-050 and NDB-048. If a pressure increase is observed in either of the wells being monitored, the stage will not continue to completion and will be flushed to depth. 11.Suspected fault or fracture that may transect the confining zones: There are no known faults within the ½ mile radius of NDB-040. Please See Attachment B. Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. 12.Detailed proposed fracturing program Attachments F & K 13.Well Clean Up procedure Attachment G Section (b) Casing Pressure Test We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test Attachment H Section (d) Pressure Relieve Valve Attachment I Proposed Wellbore Schematic Attachment J Attachment A Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Avenue Anchorage, Alaska 99501 (T) +1 907 375 4642 santos.com 1/2 , 2025 Owners, Landowners, Surface Owners and Operators See Distribution List Colville River Area North Slope Basin, Alaska Re: Notice of Operations under 20 AAC 25.283 of Oil Search (Alaska), LLCs Sundry Application for a Fracture Stimulation for the Proposed NDB-0 Well Dear Owner, Landowner, Surface Owner and/or Operator, Oil Search (Alaska), LLC (OSA) is applying for a Sundry Application under 20 AAC 25.283 to perform a fracture stimulation of the proposed NDB-0 well. This Notice is being sent by certified mail to meet the notification requirements under 20 AAC 25.283(a)(1)(A) and 20 AAC 25.283(a)(1)(B). The complete application is available for review upon request. If you wish to review the application, please contact Tim Jones, Land Manager, at the following: Tim Jones Land Manager Oil Search (Alaska), LLC 601 W 5th Ave Anchorage, AK 99501 Direct: 907-375-4624 tim.jones3@santos.com OSA, through a search of the public record, has identified you as an Owner, Landowner, Surface Owner or Operator (as defined in AOGCC regulations) within ½ mile of the proposed NDB-0 well trajectory and fracture stimulation. Please contact Tim Jones should you require additional information. Sincerely, Jacob Owens Commercial Analyst Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC ConocoPhillips Alaska, Inc. Sincerely, Jacob Owens 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL 601 W 5th Ave Anchorage, AK 99501 Repsol E&P USA LLC CERTIFIED MAIL 2455 Technology Forest Blvd. The Woodlands, TX 77381 ConocoPhillips Alaska, Inc. CERTIFIED MAIL Attn: Land Manager PO Box 100360 Anchorage AK 99510 ADL 392977 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 17.22% DNR - 82.78% ADL 392991 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.58% DNR - 58.42% ADL 392959 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 22.52% DNR - 77.48%pik ADL 392965 Surface Owners: Kuu OIL SEARCH - 51%, RE SUBS.OWNERS: ASRC - 50% DNR - 50%ADL 392985Surface Owners: KuukpikOIL SEARCH - 51%, REPSOL - 49%SUBS.OWNERS:ASRC - 49.84% DNR - 50.16%ADL 392984Surface Owners: KuukpikOIL SEARCH - 51%, REPSOL - 49%SUBS.OWNERS:ASRC - 50% DNR - 50%ADL 392958Surface Owners: KuukpikOIL SEARCH - 51%, REPSOL - 49%SUBS.OWNERS:ASRC - 36.31% DNR - 63.69%ADL 392970 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 40.29% DNR - 59.71% ADL 393024 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 45.77% DNR - 54.23% ADL 393022 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 39.48% DNR - 60.52% ADL 393021 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 19.22% DNR - 80.78% ADL 393023 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 44.08% DNR - 55.92% ADL 393019 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.1% DNR - 66.9% ADL 393018 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 29.67% DNR - 70.33% ADL 393020 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 26.59% DNR - 73.41% ADL 393016 Surface Owners: Ku OIL SEARCH - 51%, R SUBS.OWNERS: ASRC - 33.17% DNR ADL 391320 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 44.93% DNR - 55.07% ADL 391445 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391455 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD NDB-040 SURFACE LOCATION NDB-040 TRAJECTORY 0.5-MILE BUFFER NDB-040 BOTTOM HOLE PRODUCTION INTERVAL SECTIONS SANTOS LEASES DATE: 9/29/2025. By: JB 0 0.1 0.2 MilesProject: AP-DRL-GEN_assorted Layout: AP-DRL-PE_NDB40_well_ownership Map Frame: AP-DRL-PE-M_NDB-040_well_ownership GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDB-040 WELL AREA Attachment B ADL 392977 ADL 392991 ADL 392959ADL 392978 ADL 392965 ADL 392985 ADL 392984 ADL 392958 ADL 392992 ADL 392970 ADL 393024 ADL 393022 ADL 393021 ADL 393023 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 393007 ADL 391320 ADL 391445 ADL 391455 ADL 393011 COLVILLE RIVER 1 FIORD 3A FIORD 3 QUGRUK 3 QUGRUK 301 QUGRUK 3A COLVILLE RIV UNIT CD1-15 QUGRUK 8 CD1-15PB1 Colville River Unit CD1-15PB2 DW-02 NDB-011 NDB-024 NDB-025 NDB-031 NDB-032 NDB-037 NDB-051 NDBi-014 NDBi-018 NDBi-030 NDBi-036 NDBi-043A NDBi-044 NDBi-046 NDBi-049 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD NDB-040 SURFACE LOCATION NDB-040 TRAJECTORY OTHER DRILLED NDB WELLS 0.25-MILE BUFFER 0.5-MILE BUFFER NDB-040 BOTTOM HOLE NDB DRILLED WELLS BOTTOM HOLES DEVELOPMENT WELLS EXPLORATION WELLS BOTTOM HOLES OTHER WELL TRAJECTORIES BY OTHERS PRODUCTION INTERVAL SANTOS LEASES SECTIONS FAULT LINE DATE: 9/29/2025. By: JB 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB40_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDB-040 WELL NDBi-046L1 WELL NAME STATUS Casing SizeTop of Oil Pool Confining Layer (MD)Top of Oil Pool Confining Layer (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir Status Zonal IsolationCement Operations SummaryMechanical IntegrityNDBi-046/ NDBi-046L1 ACTIVE 9-5/8" 47ppf 11,166' (Nanushuk) 3,733' (Nanushuk) 10255 3,615 log open hole liner for productionTOC 10,255' & packer @ 12,572'9-5/8 x 13-3/8 Primary cement job- Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol at 3.7-4 bpm, release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 197 bbls at 4 bpm, release top pump down plug, chase with 20 bbls of water from Halliburton. Perform displacement with rig pumps, displace with 11.8 ppg OBM at 4 bpm, ICP 395 psi 8% flow, FCP 596 psi, 2% return flow, reduce rate to 3 bpm prior to plug bump: Final circulating pressure 596 psi. pressured up 500 psi over FCP 1,080 psi. Held 5 min, bled off checked floats. Floats held. CIP @ 12:45 hrs.- Total losses from cement exit shoe to cement in place: 43 bbls.Cement Evaluation Results: TOC was found to be 911 above the Top of the Nanushuk Pool (11,166 MD) at 10,255 MD. Cement isolation from the TOC down to the casing show was found to be in good quality ranging down to partial coverage in limited areas. 07/11/24, 9-5/8" casing pressure tested to 3,667 psi for 30 minutesNDB-048 ACTIVE 9-5/8" 47ppf 12,044' (Nanushuk) 3,733' (Nanushuk) 10,908'3,574'Log open hole liner for productionTOC 12,044 MD' & Packer @ 11,989 MD'First stage of cement job: Pump 82 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A downhole at 3 bpm, ~0% returns. Release bottom pump down plug for bottom plug, pump 153 bbls 15.3 ppg Versacem Tail Cement Type I/II (681 sacks, yield 1.237 cu ft/sk 1st 20 bbls Neat and last 40 bbls Neat without Bridgemaker II LCM), excess volume 30%, at 3.5 bpm, average circulating pressure 330 psi. ~5% returns throughout cement pumping. Release top pump down plug, chase plug with displacement by rig pumps, displace with 11.5 ppg OBM at 3.5 bpm, ICP 200 psi. Average ~0% returns during displacement. Bottom plug landed on calculated strokes at 3.5 bpm, 520 psi circ pressure, shear with drop in circulating pressure to 493 psi and maintain 3.5 bpm as cemenexits shoe. Circulating pressure with cement turning shoe 493 ICP at 3.5 bpm. Reduce rate to 3.0 bpm, 455 psi circ. pressure to reduce ECD. Maintain 3 bpm to plug bump, FCP 500 psi; ~0% returns with cement around shoe. Bump plug, hold for 5 minutes, to check floats, floats held, Observations for the 1st stage of the cement job: There is adequate isolation of the 9-5/8 shoe in the Top Nanushuk and good isolation in the lower Seabee formation based on the CBL log. While losses were encountered during the liner run and subsequent cement job, the CBL log indicates good cement isolation to the picked TOC at 10,908 MD. The CBL indicates good quality cement from 12,066 to 10,908, with poor to no cement from 10,908 to 9,825 MD.12/31/24, 9-5/8" casing pressure tested to 3,755 psi for 30 minutesNDBi-049 ACTIVE 9-5/8" 47ppf 11,560' (Nanushuk) 3,743' (Nanushuk) 10,477' 3,531' log open hole liner for productionTOC 10,477' & packer @ 11,438'Cement Job Execution: -1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 250 TVD above top of Nanushuk to 10,200 MD.-During execution of the 1st stage cement job, lost a reported 88 bbls after cement turned the corner, although lift pressure continued to increase during the displacement (ICP 280 psi, FCP 407 psi).-2nd Stage of cement job planned with CFLEX ~103 below the TS790. Also planned with a full 15.3 ppg tail slurry at 100% excess, targeting TOC at the 9-5/8 liner top.-During execution of the 2nd stage cement job, ~6 bbls of losses were reported and good lift pressures noted. An estimated 140 bbls Spacer, 35 bbls contaminated cement, and 65 bbls pure cement observed at surface off the top of liner. Observations/ Conclusions: -For the 1st stage of the cement job, we have adequate isolation above the top of the Nanushuk formation. This is supported by the CBL log, which indicates good cement throughout the first stage with a TOC at 10,477 MD (1083 MD / 142 TVD above top Nanushuk).-For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. -Our assessment is that we have adequate isolation across the top of the Nanushuk formation for frac operations. The 2nd stage cement job yielded adequate isolation below, across and above the Tuluvak significant hydrocarbons.12/10/24, 9-5/8" casing pressure tested to 4,020 psi for 30 minutesNDBi-050PB1 Abandonded 9-5/8" 47ppf 13,228' (Nanushuk) 3,727' (Nanushuk)Abandoned with Cased hole cement plugsCement retainer @ 13,009' MD with 45 bbls beneath retainer and 5 bbls above.The 12-1/4 intermediate hole was drilled to a depth of 13,372 MD (top of Nanushuk formation). 9-5/8 liner was run to a depth of 13,367 MD. 9-5/8 liner was set at the very top of the Nanushuk formation. Upper hydrocarbon bearing zone in the Nanushuk is the NT8 MFS. NDBi-050PB1 wellbore was drilled to 302 MD (37 TVD) above the prognosed top of the NT8 MFS. During the 1st stage cement job, both liner wiper plugs were inadvertently launched ahead of cement. When the plugs landed on the landing collar, all cement was left inside the 9-5/8 casing, with the 80 bbls of water-based spacer in the 12-1/4 x 9-5/8 annulus. -Lower Liner Section: Cement was drilled out, and a remedial cement job with 50 bbls of cement was attempted with a cement retainer in the 9-5/8 shoe track. The 9-5/8 casing was later found to be parted at 13,111 MD (above cement retainer set depth). A second cement retainer was set at 13,009 MD, and the 9-5/8 liner appeared to be parted in another location above the 2nd cement retainer. Another 50 bbls of cement was pumped to P&A the lower liner section. 45 bbls of cement was squeezed below the cement retainer, and 5 bbls were placed on top of the retainer. -Upper Liner Section: 2nd stage cement job was pumped through the Archer C-Flex stage tool per plan (325 bbls 15.3ppg cement) to isolate the Tuluvak sand. No losses were observed during the cement job and 50 bbls of cement were circulated off the liner top. Set 9-5/8 bridge plug at 3150 MD. Set 25K lbs to confirm set. Lay in 30 bbls 15.3ppg cement plug on top of bridge plug, targeting TOC 50 above surface casing shoe. Pressure test cement plug to 2000 psi for 30 min..Well is fully abandoned. NDBi-050 ACTIVELiner 1- 9-5/8" 47ppf to 9,990'. Liner 2- 7" 26 ppt to 15,137'.12,105' (Nanushuk) 3,738' (Nanushuk) 11,545' 3,671' log open hole liner for productionTOC 11,545' & packer @ 15,137'Cement Job Execution: 9-5/8 Intermediate 1 Liner-2nd Stage of cement job planned with CFLEX ~96 below the TS790. Also planned with a full 15.3 ppg tail slurry at 165% excess, targeting TOC at the 9-5/8 liner top.-During execution of the 2nd stage cement, no losses were encountered and we saw good lift pressure. An estimated 110 bbls of spacer and 120 bbls of cement observed at surface off the top of liner.7 Intermediate 2 Liner- 7 Liner cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 100 TVD above top of Nanushuk to 11,200 MD.-During execution of the 1st stage cement, we lost a reported 119 bbls during the cement job, although lift pressure continued to increase during the displacement (ICP 561 psi, FCP 878 psi). Majority of losses occurred during the last 100 bbls of displacement. 'Observation/ Conclusions: 9-5/8 Intermediate 1 Liner- For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. 7 Intermediate 2 Liner- For the 7 liner cement job, we have adequate isolation in the upper Nanushuk formations across the hydrocarbon-bearing formations (top hydrocarbon estimated within NT8 at 12,547 MD). This is supported by the CBL log, which indicates good cement throughout the Nanushuk (top of good cement at ~12,322) and an overall TOC at 11,545 MD. Our assessment is that we have adequate isolation across hydrocarbon-bearing formations in the upper Nanushuk formations, as well as adequate isolation for frac operations. The 2nd stage cement job yielded adequate isolation below, across and above the Tuluvak significant hydrocarbons.3/23/2025, 9-5/8" casing pressure tested to 4,000 psi for 30 min. 3,925' logopen hole liner for productionTOC 15,332' & packer @ 16,820'Cement Job Execution: 9-5/8 Intermediate 1 Liner:1st stage of the cement job planned with 15.3 ppg tail slurry at 30% excess, targeting TOC 1000 MD above the 9-5/8 shoe. During execution of the 1st stage cement, ~163bbls of losses were seen during the cement job with only ~14bbls lost after cement exited the shoe (good lift pressures noted). After drilling out the 9-5/8 shoe a LOT was conducted to 13.43 ppg. 2nd Stage of cement job planned with CFLEX ~53 below the TS790. Also planned with a full 15.3 ppg tail slurry at 100% excess, targeting TOC at the 9-5/8 liner top.During execution of the 2nd stage cement, no losses were encountered and we saw good lift pressure. An estimated 101 bbls of cement was observed at surface off the top of liner.7 Intermediate 2 Liner:7 Liner cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 100 TVD above top of Nanushuk to 13,300 MD.During execution of the job, a total of 290 bbls of losses were noted, with ~150bbls after the cement exited the shoe. With the near-horizontal inclination, losses, and changes in displacement rate it was difficult to identify any significant increase in the lift pressures. After drilling out the 7 shoe a LOT was conducted to 13.78ppg. Observations / Conclusions9-5/8 Intermediate 1 Liner:For the 1st stage of the cement job, based on job execution results, cement isolation was achieved across the 9-5/8 shoe.For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. 7 Intermediate 2 Liner:The SLB TOC log indicates no cement down to 15,140 MD with a transition to the TOC at 15,332 MD (3,925 TVD), and good cement bond below this depth down to the 7 shoe. The upper Nanushuk formations across the hydrocarbon-bearing formations (within NT8) have not been fully covered by cement based on the measured TOC at 15,332 MD. 6/27/2025, 9-5/8" casing pressure tested to 4,300 psi for 30 min. NDBi-036 ACTIVELiner 1- 9-5/8" 47ppf to 10,995'. Liner 2- 7" 26 ppt to 16,820'.14,331' (Nanushuk) 3,741' (Nanushuk) 15,332' 1NDB-040 is 112 ft below NDBi-050NDB-040 is 708 ft away from NDB-048NDB-040 Vertical Separation Attachment C 9-5/8 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensile (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 6870 4750 1086 8.681 8.525 10.625 15800 4.050 7 26# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensile (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 7240 5410 604 6.276 6.151 7.656 13,700 4,050 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design 9-5/8 Intermediate 1 Liner 9-5/8 Liner Top at 2,867 MD 13-3/8 Casing Shoe at 3,058 MD 9-5/8 Archer Cflex Mechanical Stage tool: 6,377 MD 9-5/8 Shoe at 9,995 MD 7 Intermediate 2 Liner 7 Liner Top at 9,850 MD Shoe at 14,921 MD Geology Top of Tuluvak Sand Top at 3,793 MD Top of Tuluvak TS 790 formation at 6,327 MD. Top of the Nanushuk picked at 13,593 MD. Cement Job Planning/Execution A summary is provided below. See attached cementing reports for additional information. 9-5/8 INT1 Liner 1st Stage Cement Job -1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting 1,000 MD above 9-5/8 shoe to ~9,000 MD. This cement job is not isolating any permeable or hydrocarbon zones. -No issues or losses were encountered running liner and cementing the 1st stage cement job. -A good FIT to 14.0ppg was achieved at the 9-5/8 shoe. -All indications of a successful 1st stage job. 9-5/8 INT1 Liner 2nd Stage Cement Job -2nd Stage of cement job planned with CFLEX ~50 below the TS790. Also planned with a full 15.3 ppg tail slurry at 100% excess, targeting TOC at the 9-5/8 liner top. This cement job is isolating the hydrocarbon zone within the upper Tuluvak formation. -Opened the CFLEX stage tool at ~6377 MD and established circulation up to 8 bpm. Pumped the 2 nd stage cement job (~381 bbls). We did lose an estimated 80 bbls during the cement job (toward the end of the job), but observed lift pressure during the job. Closed the CFLEX and set the LTP, then circulated ~50 bbls cement back to surface. -Overall, the cement job met objectives based on job parameters and cement above the liner top. 7 INT2 Liner Cement Job -1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting 200 TVD above Top Nanushuk to ~12,590 MD. Additionally, this well was planned with 160 bbl LVT spacer to be pumped ahead of the cement spacer to further lower cementing ECD. This cement job is isolating hydrocarbons in the Upper Nanushuk. -No issues or losses were encountered running liner and cementing the 1st stage cement job. -An LOT of ~13.1ppg was achieved at the 7 shoe. A SLB Sonic CBL was run on the 6-1/8 drilling BHA results are discussed below and report is attached. Observations 9-5/8 Intermediate 1 Liner: -For the 1st stage of the cement job, based on job execution results, cement isolation was achieved across the 9-5/8 shoe. -For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the hydrocarbon zone within the upper Tuluvak formation. 7 Intermediate 2 Liner: -The SLB Sonic TOC Log indicates there is good cement coverage across and above the Upper Nanushuk formations. Summary as follows: o Top of Partial Cement is 11,667' MD / 3,489' TVD - 1926' MD / 316' TVD above TNAN o Top of Good Cement is 12,486' MD / 3,592' TVD - 1107' MD / 213' TVD above TNAN o Top of Nanushuk is 13,593 MD / 3,805 TVD Good Cement Partial Cement Page 1 of 1 Cement - NDB-040 Surface Casing Cement Surface Casing Cement, Casing, 10/4/2025 06:00 Type Casing Cementing Start Date 10/4/2025 Cementing End Date 10/4/2025 Wellbore Original Hole String Surface Casing, 3,058.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results Good lift pressure observed. 42 bbls of interface (contaminated) returns and 33 bbls of clean cement returns to surface. 25 bbls losses after cement exited the shoe. Comment Cement 13-3/8 Surface Casing as follows: -Fill lines with 5 water and pressure test to 2,500 psi for 5 minutes: Good test. -Drop 1st Bottom Plug. -Pump 120 bbls of 10.5 ppg Tuned Spacer at 5.0 bpm, 320 psi. -Release 2nd Bottom Plug. -Pump 391 bbls of 11.0 ppg ArcticCem lead cement at 5 bpm, Excess Volume 150% (866 sacks, yield 2.535 cu.ft/sk). -Pump 69 bbls of 15.3 ppg Type I/II tail at 5 bpm, Excess Volume 50% (312 sacks, yield 1.24 cu.ft/sk). -Drop top plug and followed by 20 bbls wash water. -Perform displacement with rig pumps and 9.5 ppg mud. -425 bbls displaced at 2.5-6 bpm: ICP 475 psi 11% return flow, FCP 1,220 psi. -Reduce rate to 2.5 bpm prior to plug bump: Final circulating pressure 1,500 psi prior to plug bump. -Observed cement to surface at 350 bbls into displacement and swapped to take returns down bypass line to cuttings box. After swapping to bypass line, packed off at surface and opened 4" side outlet valve on conductor to take returns to cellar. -Bump plug and increase pressure to 2,000 psi, check floats: Good. -Total displacement volume 425 bbls (measured by strokes at 96% pump efficiency). -42 bbls of interface (contaminated) returns and 33 bbls of clean cement returns to surface. -Total losses from cement exit shoe to cement in place: 25 bbls. -CIP at 11:27 hrs. 1, 0.0-3,058.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 3,058.0 Full Return? No Vol Cement Ret (bbl) 75.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 5 Final Pump Rate (bbl/min) 5 Avg Pump Rate (bbl/min) 5 Final Pump Pressure (psi) 1,500.0 Plug Bump Pressure (psi) 2,000.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer (Add 8lb RED DYE to first 20 bbl) Amount (sacks) Class Volume Pumped (bbl) 120.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.82 Mix H20 Ratio (gal/sack) 12.17 Free Water (%) Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Lead Fluid Type Lead Fluid Description ArcticCem Lead Amount (sacks) 866 Class Volume Pumped (bbl) 391.0 Estimated Top (ftKB) Percent Excess Pumped (%) 150.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) Density (lb/gal) 11.00 Plastic Viscosity (cP) 23.3 Thickening Time (hr) 13.48 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 35.98 Tail Fluid Type Tail Fluid Description 15.3ppg Tail Amount (sacks) 312 Class Volume Pumped (bbl) 69.0 Estimated Top (ftKB) Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.66 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 69.8 Thickening Time (hr) 3.78 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 14.67 Page 1 of 1 Cement - NDB-040 Intermediate #1 1st StageCasing Cement Intermediate #1 1st StageCasing Cement, Casing, 10/11/2025 01:00 Type Casing Cementing Start Date 10/11/2025 Cementing End Date 10/11/2025 Wellbore Original Hole String Intermediate Liner, 9,995.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement job parameters / FIT Cement Evaluation Results No losses during cement job and good lift pressure. FIT to 14.0ppg EMW at 9-5/8" shoe. Comment Cement 1st stage 9-5/8" Intermediate liner. -Pump 5 bbls water and Pressure test cement lines to 1,000 psi low 4,000 psi high. -Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 4 bpm with 600-500 psi. -Release bottom pump down dart, chase with 80 bbls of 15.3 ppg Versacem tail cement Type I/II at 4 bpm, initial circulating pressure 675 psi. FCP 530 psi. -Open hole excess volume 30%. -Flush lines with 20 bbl. water to cuttings box. -Release top pump down dart. -Perform displacement with rig pumps and 11.5 ppg MOBM as follows: -572 bbls 11.5 ppg OBM at 4 bpm, ICP 375 psi, FCP 555 psi. (Bottom pump down dart latch up confirmed at 53 bbls displaced). -Pressured up 500 psi over FCP (1,000 psi) and held 5 min, bled off, checked floats. Floats held. -Total displacement volume 570 bbls (measured by strokes at 96% pump efficiency). -CIP at 05:35 hrs. -No losses during cement job and displacement. 1, 8,566.3-10,000.0ftKB Top Depth (ftKB) 8,566.3 Bottom Depth (ftKB) 10,000.0 Full Return? Yes Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 500.0 Plug Bump Pressure (psi) 1,000.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Mud Flush Spacer with 8# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 363 Class I/II Volume Pumped (bbl) 80.0 Estimated Top (ftKB) 9,000.0 Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 129.0 Thickening Time (hr) 7.00 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 12.50 Page 1 of 1 Cement - NDB-040 Intermediate #1 2nd Stage Casing Cement Intermediate #1 2nd Stage Casing Cement, Casing, 10/12/2025 00:30 Type Casing Cementing Start Date 10/12/2025 Cementing End Date 10/12/2025 Wellbore Original Hole String Intermediate Liner, 9,995.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement returns circulating off top of liner Cement Evaluation Results Lift pressure observed when pumping cement. 50 bbls of good cement returned to surface when circulating above the liner top after cement job. 80 bbls lost during cement job. Comment Conduct 2nd stage cementing of 9-5/8 47# Intermediate casing by open hole annulus through Archer cementing tool as follows: -Fill lines with water and test 1,000 psi low, 4,000 psi high. -Mix and pump 80 bbls of 12.5 ppg Mud Flush at bpm, ICP 453 psi, FCP 303 psi. -Mix and pump 80 bbls of 13.5 ppg Tuned Spacer at 4 bpm, ICP 258 psi. FCP 266 psi, 0 bbls lost during spacer pumping. -Mix and pump 381 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4 bpm, ICP 509 psi, Final pump rate 4 bpm, FCP 539 psi. No losses observed. -Excess Volume 100% (1772 sacks, yield 1.236 cu ft/sk) Total volume pumped 381 bbls cement. -Displace with calculated volume of 145 bbls 11.5 ppg OBM using rig pumps to Archer stage collar. -Displace cement with 62 bbls at 4 bpm, 433 psi ICP, 530 psi FCP with full returns. At 668 strokes, began losing returns, slowed to 3 bpm, then 2 bpm with 370 psi and no returns. Maintained 2 bpm to calculated 1,567 calculated strokes, with no returns, 145 bbls total displacement to Archer tool. -80 bbls total losses during cement job. -CIP at 04:45 hrs. - Circulate 50 bbls clean cement off liner top. 2, 2,856.0-6,377.0ftKB Top Depth (ftKB) 2,856.0 Bottom Depth (ftKB) 6,377.0 Full Return? Yes Vol Cement Ret (bbl) 50.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 525.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Mud Flush Spacer Fluid Type Mud Flush Spacer Fluid Description Mud Flush Spacer 8# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tuned Spacer Fluid Type Tuned Spacer Fluid Description Tuned Spacer 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 1,772 Class I/II Volume Pumped (bbl) 381.0 Estimated Top (ftKB) 2,867.0 Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 121.0 Thickening Time (hr) 6.50 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 18.50 Page 1 of 1 Cement - NDB-040 Intermediate #2 Casing Cement Intermediate #2 Casing Cement, Casing, 10/18/2025 13:30 Type Casing Cementing Start Date 10/18/2025 Cementing End Date 10/18/2025 Wellbore Original Hole String Intermediate 2 Liner, 14,921.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results SLB SonicScope TOC Log: - Top of Partial Cement is 11,667' MD / 3,489' TVD - 1926' MD / 316' TVD above TNAN. - Top of Good Cement is 12,486' MD / 3,592' TVD - 1107' MD / 213' TVD above TNAN. - Top of Nanushuk is 13,593' MD / 3,805' TVD. Comment PJSM, Cement 7 Intermediate #2 liner. - Fill lines with water and pressure test to 4,000 psi for 5 min. - Pump 160 bbls LVT at 4 bpm, 540 psi. - Pump 80 bbls of 12.5 ppg Tuned Spacer at 3.8 bpm, 625 psi. - Release bottom Pump down plug. - Pump 148 bbls of 15.3 ppg Type I/II Versacem tail at 3.7 bpm, Excess Volume 30% (998 sacks, yield 1.238 cu.ft/sk). - Wash up lines to cuttings box with 20 bbls water. - Release top pump down plug. - Perform displacement with rig pumps at 4 bpm. ICP 269 psi. FCP 950 psi with 330 bbls away. Reduce rate to 3 bpm, 718 psi to land plug at 346 bbls displacement. - Bump plug with 1,150 psi and hold for 5 mins. - Both pump down darts and liner wiper plugs landed on calculated strokes. - CIP at 17:11 hrs. - Floats held, 3.1 bbls bled back - 0 bbls lost during cement job. 1, 12,590.0-9,871.0ftKB Top Depth (ftKB) 12,590.0 Bottom Depth (ftKB) 9,871.0 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 718.0 Plug Bump Pressure (psi) 1,150.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Tuned Spacer Fluid Type Tuned Spacer Fluid Description Tuned Spacer 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem (Type I/II ) Amount (sacks) 998 Class I/II Volume Pumped (bbl) 148.0 Estimated Top (ftKB) 13,991.0 Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 117.8 Thickening Time (hr) 8.00 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 14.00 Attachment D Attachment E Attachment F Well NameNDB-04010/31/25 Draft DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT Usable J753 Encaps.# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage Cum Water Breaker BreakerPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL) 13410 (g/Mgal) (#/Mgal)aFPbFP134102 6cWF 263.54040168016804040 13370d Pump CheckWF26 404004401680018480400440 129703 60440 12970 0 0e DFITXL26 40250690 10500 28980 250 690 12720 2 6fWF26 403501040 14700 43680 350 1040 12370 2 60 1040 12370 0 00 1040 12370 0 0FLUID Neat WaterSD monitor 20 minPrime and Pressure TestOpen well- Initiate P-SleeveDisplace PT - Shut down 5 minSD monitor 2H, line up for FP with LRSPad to 4 ppaGreater than 4 ppaDFIT Dispacement to Psleeve Well NameNDB-04010/30/25 Draft DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbWF 264.05050210021005050c Pump Check WF26 402503001050012600250300 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOBSTAGE CUMSTAGE CUM Size or Stage Cum# PPA TYPE (BPM) (BBL) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) Type (BBL) (BBL)10Line out XL XL 26184040 401680 16800 0 40 34020Drop Stage 1 Ball/Collet FP 018343 43126 18060 0CSG-IV3 34330Stage 1 PADXL 2640 315358 35813230 150360 0 315 65840Slow for Seat XL 261850408 4082100 171360 0 50 70850Resume PadXL 2640 60468 4682520 196560 0 60 76861Flat; Add Patina Tracer to PODXL 2640 125593 5935250 249065027 5027CSG-IV120 88872FlatXL 2640 140733 7335880 3078610801 15828CSG-IV129 101683FlatXL 2640 170903 9037140 3792618902 34730CSG-IV150 116694FlatXL 2640 1701073 10737140 4506624252 58982CSG-IV144 1311105FlatXL 2640 1701243 12437140 5220629214 88196CSG-IV139 1450116FlatXL 2640 1701413 14137140 5934633827 122023CSG-IV134 1584127FlatXL 2640 1401553 15535880 6522631400 153423CSG-IV107 1691138FlatXL 2640 1251678 16785250 7047630991 184414CSG-IV92 1783140Clear Surface LinesXL 2640 151693 1693630 711060 184414 15 1798150Spacer XL 2640151708 1708630 717360 184414 15 1813160Drop Stage 2 Ball/Collet FP 04031711 1711126 718620 184414 3 1816170Stage 2 PADXL 2640 3062017 201712852 847140 184414 306 2122180Slow for Seat XL 2618502067 20672100 868140 184414 50 2172190Resume PadXL 2640 942161 21613948 907620 184414 94 2266201FlatXL 2640 1652326 23266930 976926635 191049CSG-IV158 2424212FlatXL 2640 1802506 25067560 10525213887 204936CSG-IV165 2589223FlatXL 2640 1952701 27018190 11344221682 226617CSG-IV172 2761234FlatXL 2640 1952896 28968190 12163227819 254436CSG-IV166 2927245FlatXL 2640 1953091 30918190 12982233510 287946CSG-IV160 3087256FlatXL 2640 1953286 32868190 13801238802 326748CSG-IV154 3241267FlatXL 2640 1853471 34717770 14578241493 368241CSG-IV141 3382278FlatXL 2640 1703641 36417140 15292242148 410388CSG-IV125 3507280Clear Surface LinesXL 2640 153656 3656630 1535520 410388 15 3522290Spacer XL 2640153671 3671630 1541820 410388 15 3537300Drop Stage 3 Ball/Collet FP 04033674 3674126 1543080 410388 3 3540310Stage 3 PADXL 2640 2953969 396912390 1666980 410388 295 3835320Slow for Seat XL 2618504019 40192100 1687980 410388 50 3885330Resume PadXL 2640 14020 402042 1688400 410388 1 3886341ScourXL 2640 604080 40802520 1713602413 41280240/70-CL57 3944353ScourXL 2640 1204200 42005040 17640013348 42615040/70-CL106 4050FLUID Neat WaterCOMMENTSEnsure Stage 1 ball/collet is loaded Prime and Pressure TestOpen well- Displace PT Well NameNDB-04010/30/25 Draft DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water360Resume PadXL 2640 504250 42502100 1785000 426150 50 4100371FlatXL 2640 2004450 44508400 1869008043 434193CSG-IV191 4291382FlatXL 2640 2254675 46759450 19635017358 451551CSG-IV207 4498394FlatXL 2640 2754950 495011550 20790039232 490783CSG-IV234 4731406FlatXL 2640 2605210 521010920 21882051736 542519CSG-IV205 4936418FlatXL 2640 2405450 545010080 22890059502 602021CSG-IV177 51144210FlatXL 2640 2005650 56508400 23730058170 660191CSG-IV138 5252430Clear Surface LinesXL 2640 155665 5665630 2379300 660191 15 5267440Spacer XL 2640155680 5680630 2385600 660191 15 5282450Drop Stage 4 Ball/Collet FP 04035683 5683126 2386860 660191 3 5285460Stage 4 PADXL 2640 2905973 597312180 2508660 660191 290 5575470Slow for Seat XL 2618506023 60232100 2529660 660191 50 5625480Resume PadXL 2640 16024 602442 2530080 660191 1 5626491ScourXL 2640 606084 60842520 2555282413 66260440/70-CL57 5684503ScourXL 2640 1206204 62045040 26056813348 67595240/70-CL106 5789510Resume PadXL 2640 506254 62542100 2626680 675952 50 5839521FlatXL 2640 2006454 64548400 2710688043 683995CSG-IV191 6031532FlatXL 2640 2256679 66799450 28051817358 701353CSG-IV207 6238544FlatXL 2640 2756954 695411550 29206839232 740585CSG-IV234 6471556FlatXL 2640 2607214 721410920 30298851736 792321CSG-IV205 6676568FlatXL 2640 2407454 745410080 31306859502 851823CSG-IV177 68545710FlatXL 2640 2007654 76548400 32146858170 909993CSG-IV138 6992580Clear Surface LinesXL 2640 157669 7669630 3220980 909993 15 7007590Spacer XL 2640157684 7684630 3227280 909993 15 7022600Drop Stage 5 Ball/Collet FP 04037687 7687126 3228540 909993 3 7025610Stage 5 PADXL 2640 2817968 796811802 3346560 909993 281 7306620Slow for Seat XL 2618508018 80182100 3367560 909993 50 7356630Resume PadXL 2640 18019 801942 3367980 909993 1 7357641ScourXL 2640 608079 80792520 3393182413 91240640/70-CL57 7414653ScourXL 2640 1208199 81995040 34435813348 92575540/70-CL106 7520660FlatXL 2640 508249 82492100 3464580 925755 50 7570671FlatXL 2640 2008449 84498400 3548588043 933797CSG-IV191 7762682FlatXL 2640 2258674 86749450 36430817358 951156CSG-IV207 7969694FlatXL 2640 2758949 894911550 37585839232 990387CSG-IV234 8202706FlatXL 2640 2609209 920910920 38677851736 1042123CSG-IV205 8407718FlatXL 2640 2409449 944910080 39685859502 1101626CSG-IV177 85847210FlatXL 2640 2009649 96498400 40525858170 1159796CSG-IV138 8723730Clear Surface LinesXL 2640 159664 9664630 4058880 1159796 15 8738740Spacer XL 2640159679 9679630 4065180 1159796 15 8753750Drop Stage 6 Ball/Collet FP 04039682 9682126 4066440 1159796 3 8756760Stage 6 PADXL 2640 2729954 995411424 4180680 1159796 272 9028770Slow for Seat XL 26185010004 100042100 4201680 1159796 50 9078780Resume PadXL 2640 110005 1000542 4202100 1159796 1 9079 Well NameNDB-04010/30/25 Draft DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water791ScourXL 2640 6010065 100652520 4227302413 116220940/70-CL57 9136803ScourXL 2640 12010185 101855040 42777013348 117555740/70-CL106 9242810FlatXL 2640 5010235 102352100 4298700 1175557 50 9292711FlatXL 2640 2009409 94098400 3951788043 1050166CSG-IV191 9484722FlatXL 2640 2259634 96349450 40462817358 1067525CSG-IV207 9691734FlatXL 2640 2759909 990911550 41617839232 1106756CSG-IV234 9924746FlatXL 2640 26010169 1016910920 42709851736 1158492CSG-IV205 10129758FlatXL 2640 24010409 1040910080 43717859502 1217995CSG-IV177 103067610FlatXL 2640 20010609 106098400 44557858170 1276164CSG-IV138 10445770Clear Surface LinesXL 2640 1510624 10624630 4462080 1276164 15 10460780Spacer XL 26401510639 10639630 4468380 1276164 15 10475790Drop Stage 7 Ball/Collet FP 040310642 10642126 4469640 1276164 3 10478800Stage 7 PADXL 2640 29410936 1093612348 4593120 1276164 294 10772810Slow for seat (XL DFIT)XL26185010986 109862100 4614120 1276164 50 10822820Resume PadXL 2640 5410289 102892268 4321380 1175557 54 10876831FlatXL 2640 19010479 104797980 4401187641 1183198CSG-IV182 11058843FlatXL 2640 21510694 106949030 44914823905 1207103CSG-IV190 11248855FlatXL 2640 24010934 1093410080 45922841243 1248346CSG-IV196 11444867FlatXL 2640 24011174 1117410080 46930853828 1302174CSG-IV183 11627879FlatXL 2640 22011394 113949240 47854859415 1361589CSG-IV157 117848811FlatXL 2640 19011584 115847980 48652858974 1420563CSG-IV128 11912890Clear Surface LinesXL 2640 1511599 11599630 4871580 1420563 15 11927900Spacer XL 26401511614 11614630 4877880 1420563 15 11942910Drop Stage 8 Ball/Collet FP 040311617 11617126 4879140 1420563 3 11945920XL Flush (DFIT)XL 2640 26411881 1188111088 4990020 1420563 264 12209930Slow for seat (XL DFIT)XL26185011931 119312100 5011020 1420563 50 1225994DFIT FlushWF 2640230 13938 121619660 597996230 12489953000 feet MD + Surface EqmtFP20 7014008 122312949 600945TOTALS14308 6009451654604 Well NameNDB-04010/30/25 Draft DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbWF3.54040168016804040cWF 261.0001680040dWF26 3.5285325 11970 13650 285 325e Pump CheckWF26 4050375 2100 15750 50 3750 375 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOBSTAGE CUMSTAGE CUM Size or Stage Cum# PPA TYPE (BPM) (BBL) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) Type (BBL) (BBL)10Line out XL XL 26184040 4151680 174300 0 40 41520Stage 8 PADXL 2640 400440 81516800 342300 0CSG-IV400 81531FlatXL 2640 180620 9957560 417907239 7239CSG-IV172 98742FlatXL 2640 180800 11757560 4935013887 21125CSG-IV165 115354FlatXL 2640 2001000 13758400 5775028532 49657CSG-IV170 132266FlatXL 2640 2001200 15758400 6615039797 89454CSG-IV158 148078FlatXL 2640 2001400 17758400 7455049585 139040CSG-IV148 1628810FlatXL 2640 2001600 19758400 8295058170 197209CSG-IV138 1766912FlatXL 2640 1751775 21507350 9030057540 254749CSG-IV114 1881100Clear Surface LinesXL 2640 151790 2165630 909300 254749 15 1896110Spacer XL 2640151805 2180630 915600 254749 15 1911120Drop Stage 9 Ball/Collet FP 04031808 2183126 916860 254749 3 1914130Stage 9 PADXL 2640 2452053 242810290 1019760 254749 245 2159140Slow for Seat XL 2618502103 24782100 1040760 254749 50 2209150Resume PadXL 2640 902193 25683780 1078560 254749 90 2299161FlatXL 2640 1902383 27587980 1158367641 262390CSG-IV182 2481173FlatXL 2640 2152598 29739030 12486623905 286295CSG-IV190 2670185FlatXL 2640 2402838 321310080 13494641243 327538CSG-IV196 2867197FlatXL 2640 2403078 345310080 14502653828 381366CSG-IV183 3050209FlatXL 2640 2203298 36739240 15426659415 440781CSG-IV157 32072111FlatXL 2640 1903488 38637980 16224658974 499755CSG-IV128 3335220Clear Surface LinesXL 2640 153503 3878630 1628760 499755 15 3350230Spacer XL 2640153518 3893630 1635060 499755 15 3365240Drop Stage 10 Ball/Collet FP 04033521 3896126 1636320 499755 3 3368250Stage 10 PADXL 2640 2373758 41339954 1735860 499755 237 3605260Slow for Seat XL 2618503808 41832100 1756860 499755 50 3655270Resume PadXL 2645 1133921 42964746 1804320 499755 113 3768281FlatXL 2645 1804101 44767560 1879927239 506994CSG-IV172 3940292FlatXL 2645 1804281 46567560 19555213887 520881CSG-IV165 4105304FlatXL 2645 2004481 48568400 20395228532 549413CSG-IV170 4275316FlatXL 2645 2004681 50568400 21235239797 589210CSG-IV158 4433328FlatXL 2645 2004881 52568400 22075249585 638795CSG-IV148 4581Stage to "Line out XL"Ensure Stage 8 ball/collet is loaded COMMENTSFLUID Neat WaterPrime and Pressure TestOpen well- Displace PTDrop BallPump Ball to Seat Well NameNDB-04010/30/25 Draft DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water3310FlatXL 2645 2005081 54568400 22915258170 696965CSG-IV138 47193412FlatXL 2645 1755256 56317350 23650257540 754504CSG-IV114 4833350Clear Surface LinesXL 2645 155271 5646630 2371320 754504 15 4848360Spacer XL 2645155286 5661630 2377620 754504 15 4863370Drop Stage 11 Ball/Collet FP 04535289 5664126 2378880 754504 3 4866380Stage 11 PADXL 2645 2295518 58939618 2475060 754504 229 5095390Slow for Seat XL 2618505568 59432100 2496060 754504 50 5145400Resume PadXL 2645 1465714 60896132 2557380 754504 146 5291411FlatXL 2645 1905904 62797980 2637187641 762145CSG-IV182 5473422FlatXL 2645 2106114 64898820 27253816201 778346CSG-IV193 5666434FlatXL 2645 2256339 67149450 032099 810445CSG-IV191 5857446FlatXL 2645 2256564 69399450 945044772 855216CSG-IV178 6035458FlatXL 2645 2256789 71649450 1890055783 911000CSG-IV166 62014610FlatXL 2645 2106999 73748820 2772061078 972078CSG-IV145 63464712FlatXL 2645 1857184 75597770 3549060827 1032906CSG-IV121 6467480Clear Surface LinesXL 2645 157199 7574630 00 1032906 15 6482490Spacer XL 2645157214 7589630 6300 1032906 15 6497500Drop Stage 12 Ball/Collet FP 04537217 7592126 7560 1032906 3 6500510Stage 12 PADXL 2645 2217438 78139282 100380 1032906 221 6721520Slow for Seat XL 2618507488 78632100 121380 1032906 50 6771530Resume PadXL 2645 1547642 80176468 186060 1032906 154 6925541FlatXL 2645 2257867 82429450 280569048 1041954CSG-IV215 7140552FlatXL 2645 2408107 848210080 3813618516 1060469CSG-IV220 7361564FlatXL 2645 2608367 874210920 4905637092 1097561CSG-IV221 7582576FlatXL 2645 2608627 900210920 5997651736 1149297CSG-IV205 7787588FlatXL 2645 2108837 92128820 6879652065 1201362CSG-IV155 7942598FlatXL 2645 408877 92521680 704769926 121128812/18-CL30 79716010FlatXL 2645 2109087 94628820 7929661145 127243312/18-CL146 8117610Clear Surface LinesXL 2645 159102 9477630 799260 1272433 15 8132620Spacer XL 2645159117 9492630 805560 1272433 15 8147630Drop Stage 13 Ball/Collet FP 04539120 9495126 806820 1272433 3 8150640Stage 13 PADXL 2645 2129332 97078904 895860 1272433 212 8362650Slow for Seat XL 2618509382 97572100 916860 1272433 50 8412660Resume PadXL 2645 1889570 99457896 995820 1272433 188 8600671FlatXL 2645 2509820 1019510500 11008210054 1282486CSG-IV239 8839682FlatXL 2645 28010100 1047511760 12184221602 1304088CSG-IV257 9097694FlatXL 2645 28010380 1075511760 13360239945 1344033CSG-IV238 9334706FlatXL 2645 28010660 1103511760 14536255716 1399749CSG-IV221 9555718FlatXL 2645 22010880 112559240 15460254544 1454292CSG-IV162 9718728FlatXL 2645 4010920 112951680 1562829926 146421912/18-CL30 97477310FlatXL 2645 22011140 115159240 16552264056 152827512/18-CL153 9900740Clear Surface LinesXL 2645 1511155 11530630 1661520 1528275 15 9915750Spacer XL 26451511170 11545630 1667820 1528275 15 9930 Well NameNDB-04010/30/25 Draft DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water760Drop Stage 14 Ball/Collet FP 045311173 11548126 1669080 1528275 3 9933770Stage 14 PADXL 2645 20311376 117518526 1754340 1528275 203 10136780Slow for Seat XL 26185011426 118012100 1775340 1528275 50 10186790Resume PadXL 2645 14711573 119486174 1837080 1528275 147 10333801FlatXL 2645 20511778 121538610 1923188244 1536519CSG-IV196 10529813FlatXL 2645 20511983 123588610 20092822794 1559313CSG-IV181 10710825FlatXL 2645 28012263 1263811760 21268848117 1607429CSG-IV229 10939837FlatXL 2645 25512518 1289310710 22339857193 1664622CSG-IV195 11134849FlatXL 2645 25512773 1314810710 23410868867 1733490CSG-IV182 113168510FlatXL 2645 22512998 133739450 24355865512 179900212/18-CL156 1147286XL FlushXL 264520 13018 13393840 56082620 1149287LG FlushWF 2645160 13178 135536720 567546160 11652883000 feet MD + Surface EqmtFP20 7013248 136232949 570495TOTALS13583 5704951799002 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 5.0 gal F103 Surfactant 1.0 Gal/mGal 1,014.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 485.0 gal J475 Breaker J475 6.0 lb/mGal 6,084.0 lbm J511 Stabilizing Agent 1.9 lb/mGal 1,938.0 lbm J532 Crosslinker 2.4 Gal/mGal 2,423.0 gal J580 Gel J580 26.0 lb/mGal 26,362.0 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 73.0 gal M002 Additive 0.0 lb/mGal 1.0 lbm M117 Clay Control Agent 338.9 lb/mGal 343,649.0 lbm M275 Bactericide 0.3 lb/mGal 304.0 lbm S522-1620 Propping Agent varied concentrations 2,989,200.0 lbm S522-4070 Propping Agent varied concentrations 63,044.0 lbm S522-1218 Propping Agent varied concentrations 210,565.0 lbm S901-1620 Proppant with Scale Inhibitor S901- 1620 varied concentrations 133,560.0 lbm S902-1620 Proppant with Scale Inhibitor S902- 16/20 varied concentrations 57,240.0 lbm ~ 69 % ~ 27 % ~ 3 % < 1 % < 1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % 100 % State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search Alaska Well: PIKKA NDB-040 Basin/Field: Pikka Fluid Name & Volume Concentration Volume Disclosure Type: Pre-Job Well Completed: Date Prepared: 11/3/2025 CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF126ST:WF126 1,013,922 gal Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate 7647-14-5 Sodium chloride 7727-54-0 Diammonium peroxodisulphate 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum 9003-35-4 Phenolic resin 50-70-4 Sorbitol 67-63-0 Propan-2-ol 56-81-5 1, 2, 3 - Propanetriol 102-71-6 2,2`,2"-nitrilotriethanol 1303-96-4 Sodium tetraborate decahydrate 68131-39-5 Ethoxylated Alcohol 37288-54-3 Beta-Mannanase 91053-39-3 Diatomaceous earth, calcined 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 14807-96-6 Magnesium silicate hydrate (talc) 9002-84-0 poly(tetrafluoroethylene) 111-42-2 2,2'-Iminodiethanol 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 127-08-2 Acetic acid, potassium salt (impurity) 14808-60-7 Quartz, Crystalline silica 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 63148-62-9 Dimethyl siloxanes and silicones 64-19-7 Acetic acid (impurity) 1310-73-2 Sodium hydroxide 68308-89-4 Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 14464-46-1 Cristobalite 532-32-1 Sodium benzoate 1338-41-6 Sorbitan stearate 9005-65-6 Sorbitan monooleate, ethoxylated 11138-66-2 Xanthan Gum 9004-32-4 Sodium carboxymethylcellulose 36089-45-9 2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-propenoate 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 9000-90-2 Amylase, alpha Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 7632-00-0 Sodium nitrite 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 2634-33-5 1,2-benzisothiazolin-3-one # SLB-Private Page: 1 / 1 Updated 10/30/202510/30/2025TBDAK TSCA StatusNorth SlopeTBDPreTBDTBDTBDTrade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SME Tracerco Carrier Fluid Soy Methyl Ester 67784-80-9 100 #VALUE! 148.5913880000T-160B Tracerco Chemical Tracer 3,5-Dibromotoluene 1611-92-3 100 #VALUE! 1.1023100000T-160C Tracerco Chemical Tracer 2,4,6-Tribromotoluene 6320-40-7 100 #VALUE! 0.4409240000T-161B Tracerco Chemical Tracer 4-Iodotoluene 624-31-7 100 #VALUE! 0.4409240000T-162A Tracerco Chemical Tracer 1,4-Dibromobenzene 106-37-6 100 #VALUE! 1.1023100000T-164B Tracerco Chemical Tracer 2-Bromonaphthalene 580-13-2 100 #VALUE! 1.1023100000T-164C Tracerco Chemical Tracer 1-Iodonaphthalene 90-14-2 100 #VALUE! 0.4409240000T-165B Tracerco Chemical Tracer 2-Iodobiphenyl 2113-51-1 100 #VALUE! 0.4409240000T-165C Tracerco Chemical Tracer 9-Bromophenanthrene 573-17-1 100 #VALUE! 0.6613860000T-166C Tracerco Chemical Tracer 1-Iodo-3,4-dimethylbenzene 31599-61-8 100 #VALUE! 1.1023100000T-716 Tracerco Chemical Tracer 1,3,5-Tribromobenzene 626-39-1 100 #VALUE! 0.4409240000T-731 Tracerco Chemical Tracer 1-Bromo-3,5-dichlorobenzene 19752-55-7 100 #VALUE! 0.4409240000T-734 Tracerco Chemical Tracer 1-Bromo-2-(trifluoromethyl)benzene 392-83-6 100 #VALUE! 0.6613860000T-168C Tracerco Chemical Tracer 1-Bromo-4-iodobenzene 589-87-7 100 #VALUE! 0.4409240000T-750 Tracerco Chemical Tracer 1,4-Dibromo-2-fluorobenzene 1435-52-5 100 #VALUE! 0.4409240000T-721 Tracerco Solid 4,4'-Dichlorobenzophenone 90-98-2 100 #VALUE! 0.4409240000T-729 Tracerco Solid 1,4-Dibromo-2,5-dimethyl benzene 1074-24-4 100 #VALUE! 2.2046200000T-751 Tracerco Solid Bis(4-bromophenyl)ether 2050-47-7 100 #VALUE! 1.5432340000Water Tracerco Carrier Fluid Water 7732-18-5 100 #VALUE! 113.5610488600T-943 Tracerco Chemical Tracer Sodium-3-chloro-2-methylbenzoate 1708942-17-9 100 #VALUE! 0.7716170000T-140C Tracerco Chemical Tracer Sodium-4-Fluorobenzoate 499-90-1 100 #VALUE! 0.7716170000T-158B Tracerco Chemical Tracer Sodium-2,5-Difluorobenzoate 522651-42-9 100 #VALUE! 0.7716170000T-158F Tracerco Chemical Tracer Sodium-2,3-Difluorobenzoate 1604819-08-0 100 #VALUE! 0.7716170000T-945 Tracerco Chemical Tracer Sodium-4-chloro-2-methylbenzoate 203261-42-1 100 #VALUE! 0.7716170000T-910 Tracerco Chemical Tracer Sodium-2-chloro-3-fluorobenzoate 1382106-83-3 100 #VALUE! 0.7716170000T-914 Tracerco Chemical Tracer Sodium-2-chloro-4,5-difluorobenzoate 1421761-16-1 100 #VALUE! 0.7716170000T-916 Tracerco Chemical Tracer Sodium-3-chloro-2,4-difluorobenzoate 1396762-34-7 100 #VALUE! 0.7716170000T-919 Tracerco Chemical Tracer Sodium-4-chloro-3-fluorobenzoate 1421029-88-0 100 #VALUE! 0.7738216200T-920 Tracerco Chemical Tracer Sodium-5-chloro-2-fluorobenzoate 1382106-78-6 100 #VALUE! 0.7760262400T-927 Tracerco Chemical Tracer Sodium-2-fluoro-3-methylbenzoate 1708942-18-0 100 #VALUE! 0.7782308600T-929 Tracerco Chemical Tracer Sodium-3-fluoro-2-methylbenzoate 1708942-24-8 100 #VALUE! 0.7804354800T-158A Tracerco Chemical Tracer Sodium-2,4-Difluorobenzoate 1765-08-8 100 #VALUE! 0.7826401000T-950 Tracerco Chemical Tracer Sodium-2-fluoro-3-(Trifluoromethyl)-benzoate 1701446-41-4 100 #VALUE! 0.7760262400Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs)County:API Number:Operator Name: Oil Search Alaska, LLCWell Name and Number: NDB-040Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For Tracerco Attachment G NDB-040 Well Clean Up Summary Flow Periods Flowback Period Duration (hours)Purpose/Remarks Ramp Up 72-96 Bring well on slowly (16/64th) via adjustable choke, change as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to reservoir proppant pack and minimize surface equipment erosion. Santos Subsurface Team will advise choke changes/rates during ramp up period. Clean Up 48+ Continue clean up period until there is a meaningful decline in solids volume to surface in combination with 2-3% WC. See Chart 1. Step Down 48-72 Measure well productivity and inflow performance. Build Up 240-336 Goal to identify linear-flow period after 10 hours. Table 1 Chart 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well flowback work. Total volume of gas per the flowback program outlined in Table 1 is approximately 15 MMscf. Well Flowback - Operational Summary: Total flowback volume (including ramp up, clean up and step down periods) not to exceed 2.0X TLTR (total load to recover) from the frac job. Santos to contact AOGCC when 1.5X TLTR is recovered and provide update on solids content and WC. If necessary, additional flowback volume exceeding 2.0X TLTR may be approved if both parties agree after reviewing actual flowback data. Target Clean Up Flow Rate: 4500 BPD & 2.2 mmscf/d. Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Subsurface Team or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. Proppant Production: Proppant production is expected and will be managed by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. Sampling: Per Surface Sampling Program below in Table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion Coriolis flow meter will be used for gas rates & volumes. Table 2 g NDB-040 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up operations as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment H NDB-040 4-1/2 Production Liner Section Summary Procedure: 1. Run 4-1/2 12.6 ppf P-110S TSH563 lower completions per tally. 2. Drop 1.125 phenolic ball during circulation to close WIV collar. 3. Pressure up to close the WIV at 1,485 psi. 4. Continue increasing pressure to start setting the liner hanger/packer at 2,500 psi. 5. Set the openhole packers and neutralize pusher tool to 4,300 psi. 6. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi for 10 min and passed. 7. Release running tool from liner hanger. 8. Flow check for 10 minutes. 9. POOH with liner hanger running tool. 10.Prepare to run upper completion. NDB-040 4-1/2 Upper Completion Section Summary Procedure: 11.Run 4-1/2 12.6 ppf P110S TSH563 tubing and downhole jewellery. 12.Circulate out the OBM from liner top to surface with 9.2 ppg NaCl Brine. 13.Land tubing hanger. 14.MIT-IA to 4,000 psi for 30 minutes on rig (planned). (Post rig move, pressure test to 4,300 psi for 30 minutes (Planned)) 15.MIT-T to 3,500 psi for 30 minutes on rig (Planned). (Post rig move, pressure test to 5,500 psi for 30 minutes (Planned)) a. Post rig more pressure test criteria: (8,800 psi MAWP 3,800 psi IA hold) * 1.1 = 5,500 psi tubing 16.Nipple down BOP stack and install 10k frac tree. 17.RDMO Attachment I Attachment J Tuluvak Sand @ 3,793' MD Top Nan 3.2 @14,979' MD Top Nanushuk @13,593' NDB-040 Well Schematic As-Built 20" Insulated Conductor128' MD 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2,867' MD 9-5/8" Liner Hanger and Liner Top Packer 2,867' MD 13-3/8" 68 ppf L-80 Surface Casing 3,058' MD 13-3/8" 68 ppf L-80 Surface Casing 3,058' MD 4-½, 12.6ppf P-110S Production Liner22,854' MD 4-½, 12.6ppf P-110S Production Liner22,854' MD 4-½ Liner Hanger/Top Packer14,715' MD 4-½ Liner Hanger/Top Packer14,715' MD GL 69.8' RKB Bottom Flange 11/04/2025 7" Tieback9,850' MD 7" Tieback9,850' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,377' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,377' MD 7" TOC (Sonic CBL)12,486' MD 7" TOC (Sonic CBL)12,486' MD 7", 26ppf L-80 Production Liner14,921' MD 7", 26ppf L-80 Production Liner14,921' MD 9-5/8", 47ppf L-80 Intermediate Liner 9,995' MD 9-5/8", 47ppf L-80 Intermediate Liner 9,995' MD 9-5/8" Primary TOC (1000' MD above shoe) 8,995' MD 9-5/8" Primary TOC (1000' MD above shoe) 8,995' MD 7" Liner Hanger and Liner Top Packer 9,850' MD 7" Liner Hanger and Liner Top Packer 9,850' MD 13 67 68 8-½ Openhole TD22,871' MD 8-½ Openhole TD22,871' MD 6664 17 21 25 29 33 37 41 45 49 53 57 61 65 9 7 6 5 4 3 2 1 6362605958565554525150484746444342403938363534323130282726242322201918161514 1211 10 7" x 9-5/8" Tieback X-over2,800' MD 7" x 9-5/8" Tieback X-over2,800' MD # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1388 1350 24 3.813 5.201 2 Gaslift Mandrel 1.5" 2277 2050 52 3.865 7.640 3 X Landing Nipple 2348 2100 54 3.813 5.201 4 D/H Psi-Temp Gauge 14460 4012 77 3.864 5.830 5 EGL Valve 14565 4035 77 3.958 5.900 6 Tieback Seal Assy (No-Go) 14715 4060 77 3.860 5.190 7 7" x 4.5" LH/Packer 14715 4060 77 5.000 5.960 8 #16 Openhole Packer 14999 4125 79 3.898 5.750 9 #15 Openhole Packer 15064 4140 81 3.898 5.750 10 #28 Tracer Carrier 15244 4160 86 3.958 5.875 11 Stg 14 - Collet Sleeve 14 15296 4162 86 3.735 5.634 12 #27 Tracer Carrier 15310 4164 87 3.958 5.875 13 #14 Openhole Packer 15609 4165 90 3.898 5.750 14 #26 Tracer Carrier 15831 4164 90 3.958 5.875 15 Stg 13 - Collet Sleeve 13 15882 4164 90 3.735 5.634 16 #25 Tracer Carrier 15896 4163 91 3.958 5.875 17 #13 Openhole Packer 16071 4160 91 3.898 5.750 18 #24 Tracer Carrier 16416 4157 91 3.958 5.875 19 Stg 12 - Collet Sleeve 12 16466 4157 91 3.735 5.634 20 #23 Tracer Carrier 16481 4157 91 3.958 5.875 21 #12 Openhole Packer 16739 4154 91 3.898 5.750 22 #22 Tracer Carrier 16961 4151 91 3.958 5.875 23 Stg 11 - Collet Sleeve 11 17012 4151 91 3.735 5.634 24 #21 Tracer Carrier 17026 4151 91 3.958 5.875 25 #11 Openhole Packer 17282 4150 91 3.898 5.750 26 #20 Tracer Carrier 17503 4146 91 3.958 5.875 27 Stg 10 - Collet Sleeve 10 17554 4146 91 3.735 5.634 28 #19 Tracer Carrier 17568 4146 91 3.958 5.875 29 #10 Openhole Packer 17866 4144 91 3.898 5.750 30 #18 Tracer Carrier 18004 4141 90 3.958 5.875 31 Stg 9 - Collet Sleeve 9 18055 4141 90 3.735 5.634 32 #17 Tracer Carrier 18069 4141 90 3.958 5.875 33 #9 Openhole Packer 18410 4138 91 3.898 5.750 34 #16 Tracer Carrier 18633 4136 91 3.958 5.875 35 Stg 8- Collet Sleeve 8 18684 4135 91 3.735 5.634 36 #15 Tracer Carrier 18698 4135 91 3.958 5.875 37 #8 Openhole Packer 18956 4132 91 3.898 5.750 38 #14 Tracer Carrier 19219 4130 91 3.958 5.875 39 Stg 7 - Collet Sleeve 7 19271 4129 91 3.735 5.634 40 #13 Tracer Carrier 19285 4129 91 3.958 5.875 41 #7 Openhole Packer 19543 4127 91 3.898 5.750 42 #12 Tracer Carrier 19765 4125 91 3.958 5.875 43 Stg 6- Collet Sleeve 6 19816 4124 91 3.735 5.634 44 #11 Tracer Carrier 19830 4124 91 3.958 5.875 45 #6 Openhole Packer 20082 4122 91 3.898 5.750 46 #10 Tracer Carrier 20343 4119 90 3.958 5.875 47 Stg 5 - Collet Sleeve 5 20395 4118 90 3.735 5.634 48 #9 Tracer Carrier 20408 4118 90 3.958 5.875 49 #5 Openhole Packer 20665 4116 91 3.898 5.750 50 #8 Tracer Carrier 20886 4114 91 3.958 5.875 51 Stg 4 - Collet Sleeve 4 20937 4113 91 3.735 5.634 52 #7 Tracer Carrier 20951 4113 91 3.958 5.875 53 #4 Openhole Packer 21210 4111 91 3.898 5.750 54 #6 Tracer Carrier 21431 4108 91 3.958 5.875 55 Stg 3 - Collet Sleeve 3 21483 4108 91 3.735 5.634 56 #5 Tracer Carrier 21497 4107 91 3.958 5.875 57 #3 Openhole Packer 21796 4105 91 3.898 5.750 58 #4 Tracer Carrier 22018 4102 91 3.958 5.875 59 Stg 2 - Collet Sleeve 2 22070 4102 91 3.735 5.634 60 #3 Tracer Carrier 22083 4102 91 3.958 5.875 61 #2 Openhole Packer 22341 4099 91 3.898 5.750 62 #2 Tracer Carrier 22562 4097 91 3.958 5.875 63 Stg 1 - Collet Sleeve 1 22613 4096 91 3.735 5.634 64 #1 Tracer Carrier 22627 4096 91 3.958 5.875 65 #1 Openhole Packer 22719 4095 91 3.898 5.750 66 Toe Sleeve 22826 4094 91 3.500 5.750 67 WIV Collar 22839 4093 91 0.875 5.620 68 Eccentric shoe 22852 4093 91 3.840 5.200 8 Tuluvak Sand @ 3,793' MD Top Nan 3.2 @14,979' MD Top Nanushuk @13,593' NDB-040 Well Schematic As-Built 20" Insulated Conductor128' MD 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2,867' MD 9-5/8" Liner Hanger and Liner Top Packer 2,867' MD 13-3/8" 68 ppf L-80 Surface Casing 3,058' MD 13-3/8" 68 ppf L-80 Surface Casing 3,058' MD 4-½, 12.6ppf P-110S Production Liner22,854' MD 4-½, 12.6ppf P-110S Production Liner22,854' MD 4-½ Liner Hanger/Top Packer14,715' MD 4-½ Liner Hanger/Top Packer14,715' MD GL 69.8' RKB Bottom Flange 11/04/2025 7" Tieback9,850' MD 7" Tieback9,850' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,377' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,377' MD 7" TOC (Sonic CBL)12,486' MD 7" TOC (Sonic CBL)12,486' MD 7", 26ppf L-80 Production Liner14,921' MD 7", 26ppf L-80 Production Liner14,921' MD 9-5/8", 47ppf L-80 Intermediate Liner 9,995' MD 9-5/8", 47ppf L-80 Intermediate Liner 9,995' MD 9-5/8" Primary TOC (1000' MD above shoe) 8,995' MD 9-5/8" Primary TOC (1000' MD above shoe) 8,995' MD 7" Liner Hanger and Liner Top Packer 9,850' MD 7" Liner Hanger and Liner Top Packer 9,850' MD 13 67 68 8-½ Openhole TD22,871' MD 8-½ Openhole TD22,871' MD 6664 17 21 25 29 33 37 41 45 49 53 57 61 65 9 7 6 5 4 3 2 1 6362605958565554525150484746444342403938363534323130282726242322201918161514 1211 10 7" x 9-5/8" Tieback X-over2,800' MD 7" x 9-5/8" Tieback X-over2,800' MD # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1388 1350 24 3.813 5.201 2 Gaslift Mandrel 1.5" 2277 2050 52 3.865 7.640 3 X Landing Nipple 2348 2100 54 3.813 5.201 4 D/H Psi-Temp Gauge 14460 4012 77 3.864 5.830 5 EGL Valve 14565 4035 77 3.958 5.900 6 Tieback Seal Assy (No-Go) 14715 4060 77 3.860 5.190 7 7" x 4.5" LH/Packer 14715 4060 77 5.000 5.960 8 #16 Openhole Packer 14999 4125 79 3.898 5.750 9 #15 Openhole Packer 15064 4140 81 3.898 5.750 10 #28 Tracer Carrier 15244 4160 86 3.958 5.875 11 Stg 14 - Collet Sleeve 14 15296 4162 86 3.735 5.634 12 #27 Tracer Carrier 15310 4164 87 3.958 5.875 13 #14 Openhole Packer 15609 4165 90 3.898 5.750 14 #26 Tracer Carrier 15831 4164 90 3.958 5.875 15 Stg 13 - Collet Sleeve 13 15882 4164 90 3.735 5.634 16 #25 Tracer Carrier 15896 4163 91 3.958 5.875 17 #13 Openhole Packer 16071 4160 91 3.898 5.750 18 #24 Tracer Carrier 16416 4157 91 3.958 5.875 19 Stg 12 - Collet Sleeve 12 16466 4157 91 3.735 5.634 20 #23 Tracer Carrier 16481 4157 91 3.958 5.875 21 #12 Openhole Packer 16739 4154 91 3.898 5.750 22 #22 Tracer Carrier 16961 4151 91 3.958 5.875 23 Stg 11 - Collet Sleeve 11 17012 4151 91 3.735 5.634 24 #21 Tracer Carrier 17026 4151 91 3.958 5.875 25 #11 Openhole Packer 17282 4150 91 3.898 5.750 26 #20 Tracer Carrier 17503 4146 91 3.958 5.875 27 Stg 10 - Collet Sleeve 10 17554 4146 91 3.735 5.634 28 #19 Tracer Carrier 17568 4146 91 3.958 5.875 29 #10 Openhole Packer 17866 4144 91 3.898 5.750 30 #18 Tracer Carrier 18004 4141 90 3.958 5.875 31 Stg 9 - Collet Sleeve 9 18055 4141 90 3.735 5.634 32 #17 Tracer Carrier 18069 4141 90 3.958 5.875 33 #9 Openhole Packer 18410 4138 91 3.898 5.750 34 #16 Tracer Carrier 18633 4136 91 3.958 5.875 35 Stg 8- Collet Sleeve 8 18684 4135 91 3.735 5.634 36 #15 Tracer Carrier 18698 4135 91 3.958 5.875 37 #8 Openhole Packer 18956 4132 91 3.898 5.750 38 #14 Tracer Carrier 19219 4130 91 3.958 5.875 39 Stg 7 - Collet Sleeve 7 19271 4129 91 3.735 5.634 40 #13 Tracer Carrier 19285 4129 91 3.958 5.875 41 #7 Openhole Packer 19543 4127 91 3.898 5.750 42 #12 Tracer Carrier 19765 4125 91 3.958 5.875 43 Stg 6- Collet Sleeve 6 19816 4124 91 3.735 5.634 44 #11 Tracer Carrier 19830 4124 91 3.958 5.875 45 #6 Openhole Packer 20082 4122 91 3.898 5.750 46 #10 Tracer Carrier 20343 4119 90 3.958 5.875 47 Stg 5 - Collet Sleeve 5 20395 4118 90 3.735 5.634 48 #9 Tracer Carrier 20408 4118 90 3.958 5.875 49 #5 Openhole Packer 20665 4116 91 3.898 5.750 50 #8 Tracer Carrier 20886 4114 91 3.958 5.875 51 Stg 4 - Collet Sleeve 4 20937 4113 91 3.735 5.634 52 #7 Tracer Carrier 20951 4113 91 3.958 5.875 53 #4 Openhole Packer 21210 4111 91 3.898 5.750 54 #6 Tracer Carrier 21431 4108 91 3.958 5.875 55 Stg 3 - Collet Sleeve 3 21483 4108 91 3.735 5.634 56 #5 Tracer Carrier 21497 4107 91 3.958 5.875 57 #3 Openhole Packer 21796 4105 91 3.898 5.750 58 #4 Tracer Carrier 22018 4102 91 3.958 5.875 59 Stg 2 - Collet Sleeve 2 22070 4102 91 3.735 5.634 60 #3 Tracer Carrier 22083 4102 91 3.958 5.875 61 #2 Openhole Packer 22341 4099 91 3.898 5.750 62 #2 Tracer Carrier 22562 4097 91 3.958 5.875 63 Stg 1 - Collet Sleeve 1 22613 4096 91 3.735 5.634 64 #1 Tracer Carrier 22627 4096 91 3.958 5.875 65 #1 Openhole Packer 22719 4095 91 3.898 5.750 66 Toe Sleeve 22826 4094 91 3.500 5.750 67 WIV Collar 22839 4093 91 0.875 5.620 68 Eccentric shoe 22852 4093 91 3.840 5.200 8 Attachment K Kinetix-Frac Completion Report Santos Country:United States Well Name:NDB-040 Operator:Santos Field:Pikka Formation:Nanushuk Prepared By: Javier M. Del Real Report Date:November 3, 2025 Table of Contents Well Description ......................................................................................................................................................................................... 4 Stage 1 ....................................................................................................................................................................................................... 5 Zoneset Simulated: ................................................................................................................................................................................ 5 Pumping Schedule Simulated: ............................................................................................................................................................... 8 Simulation Summary: ........................................................................................................................................................................... 10 Stage 2 ..................................................................................................................................................................................................... 11 Zoneset Simulated: .............................................................................................................................................................................. 11 Pumping Schedule Simulated: ............................................................................................................................................................. 15 Simulation Summary: ........................................................................................................................................................................... 16 Stage 3 ..................................................................................................................................................................................................... 17 Zoneset Simulated: .............................................................................................................................................................................. 17 Pumping Schedule Simulated: ............................................................................................................................................................. 20 Simulation Summary: ........................................................................................................................................................................... 22 Stage 4 ..................................................................................................................................................................................................... 23 Zoneset Simulated: .............................................................................................................................................................................. 23 Pumping Schedule Simulated: ............................................................................................................................................................. 27 Simulation Summary: ........................................................................................................................................................................... 29 Stage 5 ..................................................................................................................................................................................................... 30 Zoneset Simulated: .............................................................................................................................................................................. 30 Pumping Schedule Simulated: ............................................................................................................................................................. 34 Simulation Summary: ........................................................................................................................................................................... 36 Stage 6 ..................................................................................................................................................................................................... 37 Zoneset Simulated: .............................................................................................................................................................................. 37 Pumping Schedule Simulated: ............................................................................................................................................................. 41 Simulation Summary: ........................................................................................................................................................................... 43 Stage 7 ..................................................................................................................................................................................................... 44 Zoneset Simulated: .............................................................................................................................................................................. 44 Pumping Schedule Simulated: ............................................................................................................................................................. 48 Simulation Summary: ........................................................................................................................................................................... 49 Stage 8 ..................................................................................................................................................................................................... 50 Zoneset Simulated: .............................................................................................................................................................................. 50 Pumping Schedule Simulated: ............................................................................................................................................................. 54 Simulation Summary: ........................................................................................................................................................................... 55 NDB-040 (Attachment K) Stage 9 ..................................................................................................................................................................................................... 56 Zoneset Simulated: .............................................................................................................................................................................. 56 Pumping Schedule Simulated: ............................................................................................................................................................. 60 Simulation Summary: ........................................................................................................................................................................... 61 Stage 10 ................................................................................................................................................................................................... 62 Zoneset Simulated: .............................................................................................................................................................................. 62 Pumping Schedule Simulated: ............................................................................................................................................................. 66 Simulation Summary: ........................................................................................................................................................................... 67 Stage 11 ................................................................................................................................................................................................... 68 Zoneset Simulated: .............................................................................................................................................................................. 68 Pumping Schedule Simulated: ............................................................................................................................................................. 71 Simulation Summary: ........................................................................................................................................................................... 73 Stage 12 ................................................................................................................................................................................................... 74 Zoneset Simulated: .............................................................................................................................................................................. 74 Pumping Schedule Simulated: ............................................................................................................................................................. 78 Simulation Summary: ........................................................................................................................................................................... 79 Stage 13 ................................................................................................................................................................................................... 80 Zoneset Simulated: .............................................................................................................................................................................. 80 Pumping Schedule Simulated: ............................................................................................................................................................. 84 Simulation Summary: ........................................................................................................................................................................... 85 Stage 14 ................................................................................................................................................................................................... 86 Zoneset Simulated: .............................................................................................................................................................................. 86 Pumping Schedule Simulated: ............................................................................................................................................................. 90 Simulation Summary: ........................................................................................................................................................................... 91 NDB-040 (Attachment K) Well Description Completion Stages and Perforations Stage Perforation Top MD (ft) Perforation Top TVD (ft) 14 15296 4162 13 15882 4164 12 16466 4157 11 17012 4151 10 17554 4146 9 18055 4141 8 18684 4135 7 19271 4129 6 19816 4124 5 20395 4118 4 20937 4113 3 21483 4108 2 22070 4102 1 22613 4096 NDB-040 (Attachment K) Stage 1 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 1 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 15000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6603.8 psi Zoneset name: Stage 1 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4008.8 10 0.73 2936.91 1461000.32 0.22 2500 Shale 4018.8 15 0.69 2798.28 1762000.53 0.22 2500 Nanushuk 3 SS 4033.8 15.3 0.68 2740.1 1898000.54 0.22 2000 Top Nan 4049.1 6 0.65 2630 838900.21 0.27 1000 Shale 4055.1 2 0.7 2858 2665000.72 0.23 2500 Nan DS 4057.1 1.5 0.64 2584 819400.23 0.27 1500 Nan DS 4058.6 2 0.64 2615 1222000.33 0.26 1500 Nan CS 4060.6 13 0.63 2562 869100.21 0.27 1000 Nan CS 4073.6 1.5 0.61 2497.58 1002000.26 0.27 1000 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4075.1 4 0.65 2630 706600.17 0.28 1000 Nan CS 4079.1 9 0.61 2478.74 1166000.34 0.27 1000 Nan CS 4088.1 7 0.65 2659 769000.2 0.27 1000 Nan CS 4095.1 5.5 0.62 2543 1278000.4 0.26 1000 Nan CS 4100.6 13 0.65 2665 691700.19 0.28 1000 Nan DS 4113.6 2.5 0.68 2817 1748000.42 0.26 1500 Nan DS 4116.1 12.5 0.64 2621.81 1111000.32 0.27 1500 Nan DS 4128.6 4 0.7 2891 1692000.43 0.26 1500 Nan DS 4132.6 2.5 0.65 2675 822100.22 0.27 1500 Shale 4135.1 2 0.7 2882.86 2665000.72 0.23 2500 Nan DS 4137.1 4 0.65 2682.14 1159000.28 0.27 1500 Nan DS 4141.1 4 0.63 2597.72 838300.19 0.27 1000 Shale 4145.1 4 0.7 2921 2665000.72 0.23 2500 Nan DS 4149.1 6 0.65 2682 1133000.31 0.27 1500 Shale 4155.1 2 0.7 2896.8 2665000.72 0.23 2500 Nan DS 4157.1 2 0.63 2614 1078000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4159.1 6.5 0.67 2781 1694000.38 0.26 1500 Nan DS 4165.6 4 0.62 2576 898500.22 0.27 1500 Nan DS 4169.6 3.5 0.65 2711 929100.26 0.27 1500 Shale 4173.1 2 0.7 2909.35 2665000.72 0.23 2500 Nan DS 4175.1 12.5 0.65 2698 1562000.43 0.26 1500 Nan DS 4187.6 2 0.66 2747 1397000.37 0.26 1500 Shale 4189.6 2 0.7 2920.85 2665000.72 0.23 2500 Nan DS 4191.6 2 0.65 2729.38 1242000.3 0.26 1500 Shale 4193.6 8 0.69 2892.15 2665000.72 0.23 2500 Nan DS 4201.6 2 0.64 2690 932500.22 0.27 1500 Shale 4203.6 4 0.7 2931.3 2665000.72 0.23 2500 Nan DS 4207.6 6 0.65 2720.05 1427000.39 0.26 1500 Shale 4213.6 8 0.7 2939.67 2665000.72 0.23 2500 Nan DS 4221.6 6.5 0.65 2766 1469000.43 0.26 1500 Shale 4228.1 6 0.69 2915.23 2665000.72 0.23 2500 Nan DS 4234.1 2 0.64 2726 838400.22 0.27 1000 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4236.1 2 0.7 2953.26 2665000.72 0.23 2500 Nan DS 4238.1 4 0.65 2756.06 1469000.43 0.26 1500 Shale 4242.1 2 0.7 2957.44 2665000.72 0.23 2500 Nan DS 4244.1 6 0.67 2849 1545000.39 0.26 1500 Shale 4250.1 12 0.7 2966.5 2665000.72 0.23 2500 Nan DS 4262.1 2.5 0.65 2754 1214000.3 0.27 1500 Shale 4264.6 20 0.69 2945.2 2665000.72 0.23 2500 Name: Stage 1 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 1 PAD 40 YF126ST 17850 425 10.63 2 1.0 PPA 40 YF126ST 5027.69 125.02 CarboLite 16/20 + SG 1 5027.69 3.13 3 2.0 PPA 40 YF126ST 5402.26 140.04 CarboLite 16/20 + SG 2 10804.53 3.5 4 3.0 PPA 40 YF126ST 6301.07 170 CarboLite 16/20 + SG 3 18903.22 4.25 5 4.0 PPA 40 YF126ST 6063.59 170 CarboLite 16/20 + SG 4 24254.35 4.25 NDB-040 (Attachment K) Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 6 5.0 PPA 40 YF126ST 5843.36 170 CarboLite 16/20 + SG 5 29216.78 4.25 7 6.0 PPA 40 YF126ST 5638.56 170 CarboLite 16/20 + SG 6 33831.36 4.25 8 7.0 PPA 40 YF126ST 4486.29 140 CarboLite 16/20 + SG 7 31404 3.5 9 8.0 PPA 40 YF126ST 3874.4 125 CarboLite 16/20 + SG 8 30995.2 3.12 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 29.51 25.99 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 60487.22 184437.13 1635.06 40.88 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 1 6603.8 238.66 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4014 4252.66 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 1 996.56 178.94 0.28 NDB-040 (Attachment K) Stage 2 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 2 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6564 psi Zoneset name: Stage 2 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4014.8 10 0.73 2936.9 1461000.32 0.22 2500 Shale 4024.8 15 0.69 2802.4 1762000.53 0.22 2500 Nanushuk 3 SS 4039.8 15.3 0.68 2744.2 1898000.54 0.22 2000 Top Nan 4055.12 6 0.65 2630 838900.21 0.27 1000 Shale 4061.09 2 0.7 2858 2665000.72 0.23 2500 Nan DS 4063.09 1.5 0.64 2584 819400.23 0.27 1500 Nan DS 4064.6 2 0.64 2615 1222000.33 0.26 1500 Nan CS 4066.6 13 0.63 2562 869100.21 0.27 1000 Nan CS 4079.59 1.5 0.61 2501.3 1002000.26 0.27 1000 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4081.1 4 0.64 2630 706600.17 0.28 1000 Nan CS 4085.1 9 0.61 2482.4 1166000.34 0.27 1000 Nan CS 4094.09 7 0.65 2659 769000.2 0.27 1000 Nan CS 4101.12 5.5 0.62 2543 1278000.4 0.26 1000 Nan CS 4106.59 13 0.65 2665 691700.19 0.28 1000 Nan DS 4119.62 2.5 0.68 2817 1748000.42 0.26 1500 Nan DS 4122.11 12.5 0.64 2625.6 1111000.32 0.27 1500 Nan DS 4134.61 4 0.7 2891 1692000.43 0.26 1500 Nan DS 4138.62 2.5 0.65 2675 822100.22 0.27 1500 Shale 4141.11 2 0.7 2887 2665000.72 0.23 2500 Nan DS 4143.11 4 0.65 2686 1159000.28 0.27 1500 Nan DS 4147.11 4 0.63 2601.5 838300.19 0.27 1000 Shale 4151.12 4 0.7 2921 2665000.72 0.23 2500 Nan DS 4155.12 6 0.65 2682 1133000.31 0.27 1500 Shale 4161.09 2 0.7 2901 2665000.72 0.23 2500 Nan DS 4163.09 2 0.63 2614 1078000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4165.09 6.5 0.67 2781 1694000.38 0.26 1500 Nan DS 4171.59 4 0.62 2576 898500.22 0.27 1500 Nan DS 4175.59 3.5 0.65 2711 929100.26 0.27 1500 Shale 4179.1 2 0.7 2913.5 2665000.72 0.23 2500 Nan DS 4181.1 12.5 0.64 2698 1562000.43 0.26 1500 Nan DS 4193.6 2 0.65 2747 1397000.37 0.26 1500 Shale 4195.6 2 0.7 2925 2665000.72 0.23 2500 Nan DS 4197.6 2 0.65 2733.3 1242000.3 0.26 1500 Shale 4199.61 8 0.69 2896.3 2665000.72 0.23 2500 Nan DS 4207.61 2 0.64 2690 932500.22 0.27 1500 Shale 4209.61 4 0.7 2935.5 2665000.72 0.23 2500 Nan DS 4213.62 6 0.65 2723.9 1427000.39 0.26 1500 Shale 4219.62 8 0.7 2943.8 2665000.72 0.23 2500 Nan DS 4227.59 6.5 0.65 2766 1469000.43 0.26 1500 Shale 4234.09 6 0.69 2919.4 2665000.72 0.23 2500 Nan DS 4240.09 2 0.64 2726 838400.22 0.27 1000 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4242.09 2 0.7 2957.4 2665000.72 0.23 2500 Nan DS 4244.09 4 0.65 2760 1469000.43 0.26 1500 Shale 4248.1 2 0.7 2961.6 2665000.72 0.23 2500 Nan DS 4250.1 6 0.67 2849 1545000.39 0.26 1500 Shale 4256.1 12 0.7 2970.7 2665000.72 0.23 2500 Nan DS 4268.11 2.5 0.65 2754 1214000.3 0.27 1500 Shale 4270.6 20 0.69 2949.3 2665000.72 0.23 2500 NDB-040 (Attachment K) Name: Stage 2 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 2 PAD 40 YF126ST 18900 450 11.25 2 1 PPA 40 YF126ST 6636.3 165.02 CarboLite 16/20 + SG 1 6636.3 4.13 3 2 PPA 40 YF126ST 6945 180.03 CarboLite 16/20 + SG 2 13890 4.5 4 3 PPA 40 YF126ST 7230.2 195.07 CarboLite 16/20 + SG 3 21690.6 4.88 5 4 PPA 40 YF126ST 6958.4 195.09 CarboLite 16/20 + SG 4 27833.6 4.88 6 5 PPA 40 YF126ST 6706.3 195.11 CarboLite 16/20 + SG 5 33531.5 4.88 7 6 PPA 40 YF126ST 6471.8 195.12 CarboLite 16/20 + SG 6 38830.8 4.88 8 7 PPA 40 YF126ST 5932.5 185.13 CarboLite 16/20 + SG 7 41527.5 4.63 9 8 PPA 40 YF126ST 5273.3 170.13 CarboLite 16/20 + SG 8 42186.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.31 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71053.8 226126.7 1930.7 48.27 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 2 6564 240.65 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4019 4259.65 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 2 997.48 186.17 0.35 NDB-040 (Attachment K) Stage 3 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 3 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6898.6 psi Zoneset name: Stage 3 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4034.81 10 0.73 2944.99 1461000.32 0.22 2500 Shale 4044.82 15 0.69 2816.34 1762000.53 0.22 2500 Nanushuk 3 SS 4059.81 15.3 0.68 2757.75 1898000.54 0.22 2000 Top Nan 4075.1 6 0.65 2637.08 838900.21 0.27 1000 Shale 4081.1 2 0.7 2865.66 2665000.72 0.23 2500 Nan DS 4083.1 1.5 0.63 2590.95 819400.23 0.27 1500 Nan DS 4084.61 2 0.64 2622.14 1222000.33 0.26 1500 Nan CS 4086.61 13 0.63 2568.91 869100.21 0.27 1000 Nan CS 4099.61 1.5 0.61 2513.5 1002000.26 0.27 1000 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4101.12 4 0.64 2637.08 706600.17 0.28 1000 Nan CS 4105.09 9 0.61 2494.5 1166000.34 0.27 1000 Nan CS 4114.11 7 0.65 2666.08 769000.2 0.27 1000 Nan CS 4121.1 5.5 0.62 2549.76 1278000.4 0.26 1000 Nan CS 4126.61 13 0.65 2672.18 691700.19 0.28 1000 Nan DS 4139.6 2.5 0.68 2824.46 1748000.42 0.26 1500 Nan DS 4142.09 12.5 0.64 2638.38 1111000.32 0.27 1500 Nan DS 4154.59 4 0.7 2898.72 1692000.43 0.26 1500 Nan DS 4158.6 2.5 0.64 2682.04 822100.22 0.27 1500 Shale 4161.09 2 0.7 2900.9 2665000.72 0.23 2500 Nan DS 4163.09 4 0.65 2699.01 1159000.28 0.27 1500 Nan DS 4167.09 4 0.63 2614.02 838300.19 0.27 1000 Shale 4171.1 4 0.7 2928.75 2665000.72 0.23 2500 Nan DS 4175.1 6 0.64 2689.14 1133000.31 0.27 1500 Shale 4181.1 2 0.7 2914.97 2665000.72 0.23 2500 Nan DS 4183.1 2 0.63 2620.83 1078000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4185.1 6.5 0.67 2788.35 1694000.38 0.26 1500 Nan DS 4191.6 4 0.62 2582.83 898500.22 0.27 1500 Nan DS 4195.6 3.5 0.65 2718.15 929100.26 0.27 1500 Shale 4199.11 2 0.7 2927.44 2665000.72 0.23 2500 Nan DS 4201.12 12.5 0.64 2705.1 1562000.43 0.26 1500 Nan DS 4213.62 2 0.65 2754.12 1397000.37 0.26 1500 Shale 4215.58 2 0.7 2938.9 2665000.72 0.23 2500 Nan DS 4217.59 2 0.65 2746.29 1242000.3 0.26 1500 Shale 4219.59 8 0.69 2910.04 2665000.72 0.23 2500 Nan DS 4227.59 2 0.64 2696.98 932500.22 0.27 1500 Shale 4229.59 4 0.7 2949.49 2665000.72 0.23 2500 Nan DS 4233.6 6 0.65 2736.86 1427000.39 0.26 1500 Shale 4239.6 8 0.7 2957.75 2665000.72 0.23 2500 Nan DS 4247.6 6.5 0.65 2773.12 1469000.43 0.26 1500 Shale 4254.1 6 0.69 2933.24 2665000.72 0.23 2500 Nan DS 4260.1 2 0.64 2733.09 838400.22 0.27 1000 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4262.11 2 0.7 2971.39 2665000.72 0.23 2500 Nan DS 4264.11 4 0.65 2772.98 1469000.43 0.26 1500 Shale 4268.11 2 0.7 2975.59 2665000.72 0.23 2500 Nan DS 4270.11 6 0.67 2856.37 1545000.39 0.26 1500 Shale 4276.12 12 0.7 2984.73 2665000.72 0.23 2500 Nan DS 4288.09 2.5 0.64 2761.08 1214000.3 0.27 1500 Shale 4290.58 20 0.69 2963.12 2665000.72 0.23 2500 Name: Stage 3 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 3 PAD 40 YF126ST 14280 340 8.5 2 1 PPA Scour 40 YF126ST 2414.7 60.03 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120.21 CarboLite 40/70 3 13372.5 3.01 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20 + SG 1 8043 5 NDB-040 (Attachment K) Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 + SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 + SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 + SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 + SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 + SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 32.45 28.1 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71664 249856.8 1970.24 49.26 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 3 6898.6 244.03 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4038.38 4282.41 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 3 1042.55 192.35 0.38 NDB-040 (Attachment K) Stage 4 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 4 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6694.5 psi Zoneset name: Stage 4 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4024.11 10 0.73 2931.79 1461000.3 0.22 1000 Shale 4034.09 15 0.7 2808.95 1762000.5 0.22 1000 Nanushuk 3 SS 4049.11 15.3 0.68 2750.5 1898000.5 0.22 1000 Top Nan 4064.4 19.5 0.63 2566.73 900400.2 0.27 1000 Shale 4083.89 2 0.69 2822.72 2665000.7 0.23 2500 Nan DS 4085.89 1.5 0.65 2650.42 1292000.4 0.26 1000 Nan DS 4087.4 4.5 0.62 2519.16 643500.2 0.28 1000 Nan CS 4091.9 3.5 0.69 2828.67 1774000.4 0.26 1500 Nan CS 4095.41 14.5 0.66 2721.34 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4109.91 1.5 0.66 2701.33 1145000.3 0.27 1000 Nan CS 4111.38 12.5 0.64 2636.5 882100.2 0.27 1000 Nan CS 4123.88 2 0.65 2677.11 1402000.4 0.26 1500 Nan CS 4125.89 9 0.61 2507.12 853600.2 0.27 1000 Nan CS 4134.91 7 0.66 2750.35 1397000.4 0.26 1500 Nan DS 4141.9 9 0.65 2700.46 1132000.3 0.27 1500 Nan DS 4150.89 3.5 0.64 2665.94 1688000.4 0.26 1500 Nan DS 4154.4 5 0.64 2660.43 757000.2 0.27 1000 Nan DS 4159.42 2 0.7 2920.04 1795000.5 0.25 1500 Shale 4161.38 10.5 0.62 2579.21 735600.2 0.27 1000 Nan DS 4171.92 3.5 0.65 2700.31 1098000.3 0.27 1000 Nan DS 4175.39 2 0.62 2609.66 670200.2 0.28 1000 Shale 4177.4 5.5 0.66 2763.11 1300000.3 0.26 1000 Nan DS 4182.91 3.5 0.7 2908.3 1531000.4 0.26 1500 Shale 4186.38 3.5 0.64 2696.54 1193000.3 0.27 1500 Nan DS 4189.9 5.5 0.69 2897.13 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4195.41 10.5 0.64 2688.42 1171000.3 0.27 1000 Nan DS 4205.91 1.5 0.67 2805.9 1376000.4 0.26 1500 Nan DS 4207.41 5 0.62 2618.51 1139000.3 0.27 1500 Shale 4212.4 2 0.67 2804.3 1560000.5 0.26 1500 Nan DS 4214.4 4 0.64 2683.49 896400.2 0.27 1500 Nan DS 4218.41 2 0.68 2871.31 1656000.4 0.26 1500 Shale 4220.41 10 0.63 2649.26 981000.2 0.27 1500 Nan DS 4230.41 4 0.65 2768.05 1633000.4 0.26 1500 Shale 4234.42 4 0.7 2969.07 1749000.4 0.26 1500 Nan DS 4238.39 9.5 0.65 2779.21 1327000.4 0.26 1500 Shale 4247.9 2 0.62 2621.56 781500.2 0.27 1000 Nan DS 4249.9 9.5 0.69 2944.27 1692000.4 0.26 1500 Shale 4259.42 2 0.66 2807.64 1365000.4 0.26 1500 Nan DS 4261.38 2 0.7 2970.95 2665000.7 0.23 2500 Shale 4263.39 2 0.64 2712.21 1088000.3 0.27 1500 Nan DS 4265.39 2 0.7 2973.71 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4267.39 4 0.66 2839.11 1287000.3 0.26 1500 Nan DS 4271.39 19.5 0.7 2983.86 2665000.7 0.23 2500 Shale 4290.91 2 0.66 2815.47 1356000.3 0.26 1500 Nan DS 4292.91 2 0.7 2992.85 2665000.7 0.23 2500 Shale 4294.91 8 0.66 2850.14 1373000.4 0.26 1500 Nan DS 4302.89 8 0.65 2786.61 1558000.4 0.26 1500 Shale 4310.89 20 0.7 3037.09 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 4 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 4 PAD 40 YF126ST 13860 330 8.25 2 1 PPA Scour 40 YF126ST 2414.7 60.03 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120.21 CarboLite 40/70 3 13372.5 3.01 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20 + SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 + SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 + SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 + SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 + SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 + SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 32.05 27.73 NDB-040 (Attachment K) Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71244 249856.8 1960.24 49.01 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 4 6694.5 249.57 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4029.61 4279.18 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 4 843.18 216.58 0.27 NDB-040 (Attachment K) Stage 5 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 5 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6545 psi Zoneset name: Stage 5 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4028.08 10 0.73 2931.07 1461000.3 0.22 1000 Shale 4038.09 15 0.7 2811.7 1762000.5 0.22 1000 Nanushuk 3 SS 4053.08 15.3 0.68 2753.11 1898000.5 0.22 1000 Top Nan 4068.41 19.5 0.63 2569.2 900400.2 0.27 1000 Shale 4087.89 2 0.69 2825.48 2665000.7 0.23 2500 Nan DS 4089.9 1.5 0.65 2649.84 1292000.4 0.26 1000 Nan DS 4091.4 4.5 0.62 2521.63 643500.2 0.28 1000 Nan CS 4095.9 3.5 0.69 2831.43 1774000.4 0.26 1500 Nan CS 4099.41 14.5 0.66 2720.76 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4113.91 1.5 0.66 2700.75 1145000.3 0.27 1000 Nan CS 4115.39 12.5 0.64 2635.92 882100.2 0.27 1000 Nan CS 4127.89 2 0.65 2679.57 1402000.4 0.26 1500 Nan CS 4129.89 9 0.61 2509.59 853600.2 0.27 1000 Nan CS 4138.91 7 0.66 2749.63 1397000.4 0.26 1500 Nan DS 4145.9 9 0.65 2699.73 1132000.3 0.27 1500 Nan DS 4154.89 3.5 0.64 2668.55 1688000.4 0.26 1500 Nan DS 4158.4 5 0.64 2663.04 757000.2 0.27 1000 Nan DS 4163.39 2 0.7 2919.32 1795000.5 0.25 1500 Shale 4165.39 10.5 0.62 2581.67 735600.2 0.27 1000 Nan DS 4175.89 3.5 0.65 2702.92 1098000.3 0.27 1000 Nan DS 4179.4 2 0.62 2608.94 670200.2 0.28 1000 Shale 4181.4 5.5 0.66 2765.72 1300000.3 0.26 1000 Nan DS 4186.91 3.5 0.7 2911.2 1531000.4 0.26 1500 Shale 4190.39 3.5 0.64 2695.82 1193000.3 0.27 1500 Nan DS 4193.9 5.5 0.69 2899.88 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4199.41 10.5 0.64 2691.03 1171000.3 0.27 1000 Nan DS 4209.91 1.5 0.67 2808.51 1376000.4 0.26 1500 Nan DS 4211.38 5 0.62 2620.98 1139000.3 0.27 1500 Shale 4216.4 2 0.66 2803.72 1560000.5 0.26 1500 Nan DS 4218.41 4 0.64 2682.91 896400.2 0.27 1500 Nan DS 4222.41 2 0.68 2870.59 1656000.4 0.26 1500 Shale 4224.41 10 0.63 2651.72 981000.2 0.27 1500 Nan DS 4234.42 4 0.65 2770.51 1633000.4 0.26 1500 Shale 4238.39 4 0.7 2968.34 1749000.4 0.26 1500 Nan DS 4242.39 9.5 0.65 2781.82 1327000.4 0.26 1500 Shale 4251.9 2 0.62 2624.02 781500.2 0.27 1000 Nan DS 4253.9 9.5 0.69 2947.02 1692000.4 0.26 1500 Shale 4263.39 2 0.66 2810.25 1365000.4 0.26 1500 Nan DS 4265.39 2 0.7 2973.71 2665000.7 0.23 2500 Shale 4267.39 2 0.64 2714.67 1088000.3 0.27 1500 Nan DS 4269.39 2 0.7 2976.46 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4271.39 4 0.66 2841.72 1287000.3 0.26 1500 Nan DS 4275.39 19.5 0.7 2986.76 2665000.7 0.23 2500 Shale 4294.91 2 0.66 2818.23 1356000.3 0.26 1500 Nan DS 4296.92 2 0.7 2995.61 2665000.7 0.23 2500 Shale 4298.88 8 0.66 2852.75 1373000.4 0.26 1500 Nan DS 4306.89 8 0.65 2789.08 1558000.4 0.26 1500 Shale 4314.9 20 0.7 3036.37 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 5 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 5 PAD 40 YF126ST 13440 320 8 2 1 PPA Scour 40 YF126ST 2414.7 60.03 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120.21 CarboLite 40/70 3 13372.5 3.01 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20 + SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 + SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 + SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 + SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 + SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 + SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 31.64 27.36 NDB-040 (Attachment K) Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 70824 249856.8 1950.24 48.76 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 5 6545 249.12 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4033 4282.12 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 5 839.25 213.71 0.28 NDB-040 (Attachment K) Stage 6 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 6 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6380.6 psi Zoneset name: Stage 6 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4032.09 10 0.73 2933.24 1461000.3 0.22 1000 Shale 4042.09 15 0.69 2814.46 1762000.5 0.22 1000 Nanushuk 3 SS 4057.09 15.3 0.68 2755.86 1898000.5 0.22 1000 Top Nan 4072.41 19.5 0.63 2571.81 900400.2 0.27 1000 Shale 4091.9 2 0.69 2828.09 2665000.7 0.23 2500 Nan DS 4093.9 1.5 0.65 2651.72 1292000.4 0.26 1000 Nan DS 4095.41 4.5 0.62 2524.09 643500.2 0.28 1000 Nan CS 4099.9 3.5 0.69 2834.18 1774000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4103.41 14.5 0.66 2722.65 1388000.3 0.26 1500 Nan CS 4117.91 1.5 0.66 2702.78 1145000.3 0.27 1000 Nan CS 4119.39 12.5 0.64 2637.8 882100.2 0.27 1000 Nan CS 4131.89 2 0.65 2682.18 1402000.4 0.26 1500 Nan CS 4133.89 9 0.61 2511.91 853600.2 0.27 1000 Nan CS 4142.91 7 0.66 2751.66 1397000.4 0.26 1500 Nan DS 4149.9 9 0.65 2701.76 1132000.3 0.27 1500 Nan DS 4158.89 3.5 0.64 2671.16 1688000.4 0.26 1500 Nan DS 4162.4 5 0.64 2665.5 757000.2 0.27 1000 Nan DS 4167.39 2 0.7 2921.5 1795000.5 0.25 1500 Shale 4169.39 10.5 0.62 2584.14 735600.2 0.27 1000 Nan DS 4179.89 3.5 0.65 2705.53 1098000.3 0.27 1000 Nan DS 4183.4 2 0.62 2610.82 670200.2 0.28 1000 Shale 4185.4 5.5 0.66 2768.34 1300000.3 0.26 1000 Nan DS 4190.91 3.5 0.7 2913.95 1531000.4 0.26 1500 Shale 4194.39 3.5 0.64 2697.85 1193000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4197.9 5.5 0.69 2902.64 1416000.4 0.26 1500 Nan DS 4203.41 10.5 0.64 2693.5 1171000.3 0.27 1000 Nan DS 4213.91 1.5 0.67 2811.12 1376000.4 0.26 1500 Nan DS 4215.39 5 0.62 2623.44 1139000.3 0.27 1500 Shale 4220.41 2 0.66 2805.61 1560000.5 0.26 1500 Nan DS 4222.41 4 0.64 2684.79 896400.2 0.27 1500 Nan DS 4226.41 2 0.68 2872.62 1656000.4 0.26 1500 Shale 4228.41 10 0.63 2654.34 981000.2 0.27 1500 Nan DS 4238.39 4 0.65 2773.27 1633000.4 0.26 1500 Shale 4242.39 4 0.7 2970.52 1749000.4 0.26 1500 Nan DS 4246.39 9.5 0.66 2784.58 1327000.4 0.26 1500 Shale 4255.91 2 0.62 2626.49 781500.2 0.27 1000 Nan DS 4257.91 9.5 0.69 2949.78 1692000.4 0.26 1500 Shale 4267.39 2 0.66 2812.86 1365000.4 0.26 1500 Nan DS 4269.39 2 0.7 2976.46 2665000.7 0.23 2500 Shale 4271.39 2 0.64 2717.28 1088000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4273.39 2 0.7 2979.22 2665000.7 0.23 2500 Shale 4275.39 4 0.67 2844.48 1287000.3 0.26 1500 Nan DS 4279.4 19.5 0.7 2989.52 2665000.7 0.23 2500 Shale 4298.88 2 0.66 2820.69 1356000.3 0.26 1500 Nan DS 4300.89 2 0.7 2998.37 2665000.7 0.23 2500 Shale 4302.89 8 0.66 2855.5 1373000.4 0.26 1500 Nan DS 4310.89 8 0.65 2791.83 1558000.4 0.26 1500 Shale 4318.9 20 0.7 3038.54 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 6 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 6 PAD 40 YF126ST 13020 310 7.75 2 1 PPA Scour 40 YF126ST 2414.7 60.03 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120.21 CarboLite 40/70 3 13372.5 3.01 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20 + SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 + SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 + SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 + SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 + SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 + SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 31.24 26.99 NDB-040 (Attachment K) Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 70404 249856.8 1940.24 48.51 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 6 6380.6 247.79 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4038.24 4286.03 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 6 826.99 212.81 0.28 NDB-040 (Attachment K) Stage 7 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 7 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6485.2 psi Zoneset name: Stage 7 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4036.09 10 0.72 2918.88 1461000.3 0.22 1000 Shale 4046.1 15 0.69 2817.21 1762000.5 0.22 1000 Nanushuk 3 SS 4061.09 15.3 0.68 2758.62 1898000.5 0.22 1000 Top Nan CS 4076.41 19.5 0.63 2574.27 900400.2 0.27 1000 Nan SS 4095.9 2 0.69 2830.99 2665000.7 0.23 2500 Nan CS 4097.9 1.5 0.64 2638.96 1292000.4 0.26 1000 Nan CS 4099.41 4.5 0.62 2526.56 643500.2 0.28 1000 Nan DS 4103.9 3.5 0.69 2837.08 1774000.4 0.26 1500 Nan DS 4107.41 14.5 0.66 2709.6 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4121.92 1.5 0.65 2689.72 1145000.3 0.27 1000 Nan CS 4123.39 12.5 0.64 2625.04 882100.2 0.27 1000 Nan DS 4135.89 2 0.65 2684.94 1402000.4 0.26 1500 Nan CS 4137.89 9 0.61 2514.37 853600.2 0.27 1000 Nan DS 4146.92 7 0.66 2738.46 1397000.4 0.26 1500 Nan DS 4153.9 9 0.65 2688.85 1132000.3 0.27 1500 Nan DS 4162.89 3.5 0.64 2673.77 1688000.4 0.26 1500 Nan DS 4166.4 5 0.64 2668.11 757000.2 0.27 1000 Nan DS 4171.39 2 0.7 2907.57 1795000.5 0.25 1500 Nan CS 4173.39 10.5 0.62 2586.6 735600.2 0.27 1000 Nan CS 4183.89 3.5 0.65 2708.14 1098000.3 0.27 1000 Nan CS 4187.4 2 0.62 2598.5 670200.2 0.28 1000 Nan CS 4189.4 5.5 0.66 2770.95 1300000.3 0.26 1000 Nan DS 4194.91 3.5 0.69 2916.56 1531000.4 0.26 1500 Nan DS 4198.39 3.5 0.64 2685.08 1193000.3 0.27 1500 Nan DS 4201.9 5.5 0.69 2905.4 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4207.41 10.5 0.64 2696.11 1171000.3 0.27 1000 Nan DS 4217.91 1.5 0.67 2813.88 1376000.4 0.26 1500 Nan DS 4219.39 5 0.62 2626.05 1139000.3 0.27 1500 Nan DS 4224.41 2 0.66 2792.56 1560000.5 0.26 1500 Nan DS 4226.41 4 0.63 2672.18 896400.2 0.27 1500 Nan DS 4230.41 2 0.68 2859.13 1656000.4 0.26 1500 Nan DS 4232.41 10 0.63 2656.8 981000.2 0.27 1500 Nan DS 4242.39 4 0.65 2775.88 1633000.4 0.26 1500 Nan DS 4246.39 4 0.7 2956.59 1749000.4 0.26 1500 Nan DS 4250.39 9.5 0.66 2787.19 1327000.4 0.26 1500 Nan DS 4259.91 2 0.62 2628.95 781500.2 0.27 1000 Nan DS 4261.91 9.5 0.69 2952.53 1692000.4 0.26 1500 Nan DS 4271.39 2 0.66 2815.47 1365000.4 0.26 1500 Shale 4273.39 2 0.7 2979.22 2665000.7 0.23 2500 Nan DS 4275.39 2 0.64 2719.75 1088000.3 0.27 1500 Shale 4277.4 2 0.7 2982.12 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4279.4 4 0.67 2847.24 1287000.3 0.26 1500 Shale 4283.4 19.5 0.7 2992.42 2665000.7 0.23 2500 Nan DS 4302.89 2 0.66 2823.45 1356000.3 0.26 1500 Shale 4304.89 2 0.7 3001.12 2665000.7 0.23 2500 Nan DS 4306.89 8 0.66 2858.11 1373000.4 0.26 1500 Nan DS 4314.9 8 0.65 2794.3 1558000.4 0.26 1500 Shale 4322.9 20 0.7 3024.62 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 7 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 7 PAD 40 YF126ST 16800 400 CarboLite 16/20 + SG 0 0 10 2 1 PPA 40 YF126ST 7641.8 190.02 CarboLite 16/20 + SG 1 7641.8 4.75 3 3 PPA 40 YF126ST 7971.7 215.07 CarboLite 16/20 + SG 3 23915.1 5.38 4 5 PPA 40 YF126ST 8253.9 240.13 CarboLite 16/20 + SG 5 41269.5 6 5 7 PPA 40 YF126ST 7696.2 240.17 CarboLite 16/20 + SG 7 53873.4 6 6 9 PPA 40 YF126ST 6608.3 220.19 CarboLite 16/20 + SG 9 59474.7 5.5 7 11 PPA 40 YF126ST 5367.5 190.19 CarboLite 16/20 + SG 11 59042.5 4.75 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.84 23.59 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 60339.4 245217 1695.77 42.39 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 7 6485.2 244.84 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4042.78 4287.62 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 7 773.22 207.26 0.37 NDB-040 (Attachment K) Stage 8 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 8 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6595 psi Zoneset name: Stage 8 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4041.11 10 0.72 2922.51 1461000.3 0.22 1000 Shale 4051.12 15 0.69 2820.69 1762000.5 0.22 1000 Nanushuk 3 SS 4066.11 15.3 0.68 2762.1 1898000.5 0.22 1000 Top Nan CS 4081.4 19.5 0.63 2577.47 900400.2 0.27 1000 Nan SS 4100.89 2 0.69 2834.33 2665000.7 0.23 2500 Nan CS 4102.89 1.5 0.64 2642.15 1292000.4 0.26 1000 Nan CS 4104.4 4.5 0.62 2529.75 643500.2 0.28 1000 Nan DS 4108.89 3.5 0.69 2840.42 1774000.4 0.26 1500 Nan DS 4112.4 14.5 0.66 2712.79 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4126.9 1.5 0.65 2692.92 1145000.3 0.27 1000 Nan CS 4128.41 12.5 0.64 2628.23 882100.2 0.27 1000 Nan DS 4140.91 2 0.65 2688.13 1402000.4 0.26 1500 Nan CS 4142.91 9 0.61 2517.42 853600.2 0.27 1000 Nan DS 4151.9 7 0.66 2741.79 1397000.4 0.26 1500 Nan DS 4158.89 9 0.65 2692.05 1132000.3 0.27 1500 Nan DS 4167.91 3.5 0.64 2676.96 1688000.4 0.26 1500 Nan DS 4171.39 5 0.64 2671.31 757000.2 0.27 1000 Nan DS 4176.41 2 0.7 2911.05 1795000.5 0.25 1500 Nan CS 4178.41 10.5 0.62 2589.79 735600.2 0.27 1000 Nan CS 4188.91 3.5 0.65 2711.34 1098000.3 0.27 1000 Nan CS 4192.39 2 0.62 2601.54 670200.2 0.28 1000 Nan CS 4194.39 5.5 0.66 2774.28 1300000.3 0.26 1000 Nan DS 4199.9 3.5 0.69 2920.04 1531000.4 0.26 1500 Nan DS 4203.41 3.5 0.64 2688.27 1193000.3 0.27 1500 Nan DS 4206.89 5.5 0.69 2908.88 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4212.4 10.5 0.64 2699.3 1171000.3 0.27 1000 Nan DS 4222.9 1.5 0.67 2817.21 1376000.4 0.26 1500 Nan DS 4224.41 5 0.62 2629.1 1139000.3 0.27 1500 Nan DS 4229.4 2 0.66 2795.75 1560000.5 0.26 1500 Nan DS 4231.4 4 0.63 2675.37 896400.2 0.27 1500 Nan DS 4235.4 2 0.68 2862.46 1656000.4 0.26 1500 Nan DS 4237.4 10 0.63 2659.99 981000.2 0.27 1500 Nan DS 4247.41 4 0.65 2779.07 1633000.4 0.26 1500 Nan DS 4251.41 4 0.7 2960.08 1749000.4 0.26 1500 Nan DS 4255.41 9.5 0.66 2790.38 1327000.4 0.26 1500 Nan DS 4264.9 2 0.62 2632 781500.2 0.27 1000 Nan DS 4266.9 9.5 0.69 2956.01 1692000.4 0.26 1500 Nan DS 4276.41 2 0.66 2818.81 1365000.4 0.26 1500 Shale 4278.41 2 0.7 2982.7 2665000.7 0.23 2500 Nan DS 4280.41 2 0.64 2722.94 1088000.3 0.27 1500 Shale 4282.41 2 0.7 2985.6 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4284.42 4 0.67 2850.57 1287000.3 0.26 1500 Shale 4288.39 19.5 0.7 2995.9 2665000.7 0.23 2500 Nan DS 4307.91 2 0.66 2826.64 1356000.3 0.26 1500 Shale 4309.91 2 0.7 3004.6 2665000.7 0.23 2500 Nan DS 4311.91 8 0.66 2861.45 1373000.4 0.26 1500 Nan DS 4319.91 8 0.65 2797.63 1558000.4 0.26 1500 Shale 4327.89 20 0.7 3028.1 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 8 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 8 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 7238.8 180 CarboLite 16/20 + SG 1 7238.8 4.5 3 2 PPA 40 YF126ST 6943.6 180 CarboLite 16/20 + SG 2 13887.2 4.5 4 4 PPA 40 YF126ST 7133.8 200 CarboLite 16/20 + SG 4 28535.2 5 5 6 PPA 40 YF126ST 6633.6 200 CarboLite 16/20 + SG 6 39801.6 5 6 8 PPA 40 YF126ST 6199.2 200 CarboLite 16/20 + SG 8 49593.6 5 7 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 + SG 10 58180 5 8 12 PPA 40 YF126ST 4796 175 CarboLite 16/20 + SG 12 57552 4.38 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.29 23.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 61563 254788.4 1735.01 43.38 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 8 6595 246.7 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4047.05 4293.75 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 8 812.44 209.38 0.38 NDB-040 (Attachment K) Stage 9 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 9 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6111.5 psi Zoneset name: Stage 9 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4047.11 10 0.72 2926.72 1461000.3 0.22 1000 Shale 4057.09 15 0.69 2824.9 1762000.5 0.22 1000 Nanushuk 3 SS 4072.11 15.3 0.68 2766.16 1898000.5 0.22 1000 Top Nan CS 4087.4 19.5 0.63 2581.24 900400.2 0.27 1000 Nan SS 4106.89 2 0.69 2838.53 2665000.7 0.23 2500 Nan CS 4108.89 1.5 0.64 2645.92 1292000.4 0.26 1000 Nan CS 4110.4 4.5 0.62 2533.37 643500.2 0.28 1000 Nan DS 4114.9 3.5 0.69 2844.63 1774000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4118.41 14.5 0.66 2716.85 1388000.3 0.26 1500 Nan CS 4132.91 1.5 0.65 2696.83 1145000.3 0.27 1000 Nan CS 4134.42 12.5 0.64 2632.14 882100.2 0.27 1000 Nan DS 4146.92 2 0.65 2692.05 1402000.4 0.26 1500 Nan CS 4148.88 9 0.61 2521.05 853600.2 0.27 1000 Nan DS 4157.91 7 0.66 2745.71 1397000.4 0.26 1500 Nan DS 4164.9 9 0.65 2695.96 1132000.3 0.27 1500 Nan DS 4173.88 3.5 0.64 2680.88 1688000.4 0.26 1500 Nan DS 4177.4 5 0.64 2675.08 757000.2 0.27 1000 Nan DS 4182.41 2 0.7 2915.26 1795000.5 0.25 1500 Nan CS 4184.42 10.5 0.62 2593.42 735600.2 0.27 1000 Nan CS 4194.91 3.5 0.65 2715.25 1098000.3 0.27 1000 Nan CS 4198.39 2 0.62 2605.31 670200.2 0.28 1000 Nan CS 4200.39 5.5 0.66 2778.2 1300000.3 0.26 1000 Nan DS 4205.91 3.5 0.69 2924.25 1531000.4 0.26 1500 Nan DS 4209.42 3.5 0.64 2692.05 1193000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4212.89 5.5 0.69 2913.08 1416000.4 0.26 1500 Nan CS 4218.41 10.5 0.64 2703.21 1171000.3 0.27 1000 Nan DS 4228.9 1.5 0.67 2821.13 1376000.4 0.26 1500 Nan DS 4230.41 5 0.62 2632.87 1139000.3 0.27 1500 Nan DS 4235.4 2 0.66 2799.81 1560000.5 0.26 1500 Nan DS 4237.4 4 0.63 2679.14 896400.2 0.27 1500 Nan DS 4241.4 2 0.68 2866.53 1656000.4 0.26 1500 Nan DS 4243.41 10 0.63 2663.76 981000.2 0.27 1500 Nan DS 4253.41 4 0.65 2782.98 1633000.4 0.26 1500 Nan DS 4257.41 4 0.7 2964.28 1749000.4 0.26 1500 Nan DS 4261.38 9.5 0.66 2794.3 1327000.4 0.26 1500 Nan DS 4270.9 2 0.62 2635.77 781500.2 0.27 1000 Nan DS 4272.9 9.5 0.69 2960.08 1692000.4 0.26 1500 Nan DS 4282.41 2 0.66 2822.72 1365000.4 0.26 1500 Shale 4284.42 2 0.7 2986.91 2665000.7 0.23 2500 Nan DS 4286.38 2 0.64 2726.85 1088000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4288.39 2 0.7 2989.66 2665000.7 0.23 2500 Nan DS 4290.39 4 0.67 2854.49 1287000.3 0.26 1500 Shale 4294.39 19.5 0.7 3000.11 2665000.7 0.23 2500 Nan DS 4313.91 2 0.66 2830.56 1356000.3 0.26 1500 Shale 4315.91 2 0.7 3008.81 2665000.7 0.23 2500 Nan DS 4317.91 8 0.66 2865.37 1373000.4 0.26 1500 Nan DS 4325.89 8 0.65 2801.4 1558000.4 0.26 1500 Shale 4333.89 20 0.7 3032.16 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 9 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 9 PAD 40 YF126ST 16170 385 9.62 2 1 PPA 40 YF126ST 7641.8 190.02 CarboLite 16/20 + SG 1 7641.8 4.75 3 3 PPA 40 YF126ST 7971.7 215.07 CarboLite 16/20 + SG 3 23915.1 5.38 4 5 PPA 40 YF126ST 8253.9 240.13 CarboLite 16/20 + SG 5 41269.5 6 5 7 PPA 40 YF126ST 7696.2 240.17 CarboLite 16/20 + SG 7 53873.4 6 6 9 PPA 40 YF126ST 6608.3 220.19 CarboLite 16/20 + SG 9 59474.7 5.5 7 11 PPA 40 YF126ST 5367.5 190.19 CarboLite 16/20 + SG 11 59042.5 4.75 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.08 22.91 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59709.4 245217 1680.77 42.02 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 9 6111.5 244.68 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4053.84 4298.52 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 9 774.3 206.76 0.39 NDB-040 (Attachment K) Stage 10 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 10 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7312.6 psi Zoneset name: Stage 10 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4053.12 10 0.72 2931.07 1461000.3 0.22 1000 Shale 4063.09 15 0.69 2829.11 1762000.5 0.22 1000 Nanushuk 3 SS 4078.12 15.3 0.68 2770.22 1898000.5 0.22 1000 Top Nan CS 4093.41 19.5 0.63 2585.01 900400.2 0.27 1000 Nan SS 4112.89 2 0.69 2842.74 2665000.7 0.23 2500 Nan CS 4114.9 1.5 0.64 2649.84 1292000.4 0.26 1000 Nan CS 4116.4 4.5 0.62 2537.15 643500.2 0.28 1000 Nan DS 4120.9 3.5 0.69 2848.83 1774000.4 0.26 1500 Nan DS 4124.41 14.5 0.66 2720.76 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4138.91 1.5 0.65 2700.75 1145000.3 0.27 1000 Nan CS 4140.39 12.5 0.64 2635.92 882100.2 0.27 1000 Nan DS 4152.89 2 0.65 2695.96 1402000.4 0.26 1500 Nan CS 4154.89 9 0.61 2524.67 853600.2 0.27 1000 Nan DS 4163.91 7 0.66 2749.77 1397000.4 0.26 1500 Nan DS 4170.9 9 0.65 2699.88 1132000.3 0.27 1500 Nan DS 4179.89 3.5 0.64 2684.65 1688000.4 0.26 1500 Nan DS 4183.4 5 0.64 2678.99 757000.2 0.27 1000 Nan DS 4188.39 2 0.7 2919.46 1795000.5 0.25 1500 Nan CS 4190.39 10.5 0.62 2597.19 735600.2 0.27 1000 Nan CS 4200.89 3.5 0.65 2719.17 1098000.3 0.27 1000 Nan CS 4204.4 2 0.62 2609.08 670200.2 0.28 1000 Nan CS 4206.4 5.5 0.66 2782.26 1300000.3 0.26 1000 Nan DS 4211.91 3.5 0.69 2928.46 1531000.4 0.26 1500 Nan DS 4215.39 3.5 0.64 2695.82 1193000.3 0.27 1500 Nan DS 4218.9 5.5 0.69 2917.14 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4224.41 10.5 0.64 2706.98 1171000.3 0.27 1000 Nan DS 4234.91 1.5 0.67 2825.19 1376000.4 0.26 1500 Nan DS 4236.42 5 0.62 2636.64 1139000.3 0.27 1500 Nan DS 4241.4 2 0.66 2803.72 1560000.5 0.26 1500 Nan DS 4243.41 4 0.63 2682.91 896400.2 0.27 1500 Nan DS 4247.41 2 0.68 2870.59 1656000.4 0.26 1500 Nan DS 4249.41 10 0.63 2667.53 981000.2 0.27 1500 Nan DS 4259.42 4 0.65 2786.9 1633000.4 0.26 1500 Nan DS 4263.39 4 0.7 2968.49 1749000.4 0.26 1500 Nan DS 4267.39 9.5 0.66 2798.21 1327000.4 0.26 1500 Nan DS 4276.9 2 0.62 2639.4 781500.2 0.27 1000 Nan DS 4278.9 9.5 0.69 2964.28 1692000.4 0.26 1500 Nan DS 4288.39 2 0.66 2826.79 1365000.4 0.26 1500 Shale 4290.39 2 0.7 2991.11 2665000.7 0.23 2500 Nan DS 4292.39 2 0.64 2730.63 1088000.3 0.27 1500 Shale 4294.39 2 0.7 2993.87 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4296.39 4 0.67 2858.4 1287000.3 0.26 1500 Shale 4300.39 19.5 0.7 3004.17 2665000.7 0.23 2500 Nan DS 4319.91 2 0.66 2834.62 1356000.3 0.26 1500 Shale 4321.92 2 0.7 3013.01 2665000.7 0.23 2500 Nan DS 4323.92 8 0.66 2869.43 1373000.4 0.26 1500 Nan DS 4331.89 8 0.65 2805.32 1558000.4 0.26 1500 Shale 4339.9 20 0.7 3036.37 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 10 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 10 PAD 45 YF126ST 16800 400 8.89 2 1 PPA 45 YF126ST 7238.8 180 CarboLite 16/20 + SG 1 7238.8 4 3 2 PPA 45 YF126ST 6943.6 180 CarboLite 16/20 + SG 2 13887.2 4 4 4 PPA 45 YF126ST 7133.8 200 CarboLite 16/20 + SG 4 28535.2 4.44 5 6 PPA 45 YF126ST 6633.6 200 CarboLite 16/20 + SG 6 39801.6 4.44 6 8 PPA 45 YF126ST 6199.2 200 CarboLite 16/20 + SG 8 49593.6 4.44 7 10 PPA 45 YF126ST 5818 200 CarboLite 16/20 + SG 10 58180 4.44 8 12 PPA 45 YF126ST 4796 175 CarboLite 16/20 + SG 12 57552 3.89 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.29 23.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 61563 254788.4 1735.01 38.56 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 10 7312.6 250.27 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4058.03 4308.3 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 10 830.89 211.3 0.42 NDB-040 (Attachment K) Stage 11 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 11 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7141.4 psi Zoneset name: Stage 11 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4061.1 10 0.72 2936.9 1461000.3 0.22 1000 Shale 4071.1 15 0.69 2834.6 1762000.5 0.22 1000 Nanushuk 3 SS 4086.1 15.3 0.68 2775.6 1898000.5 0.22 1000 Top Nan CS 4101.4 19.5 0.63 2590 900400.2 0.27 1000 Nan SS 4120.9 2 0.69 2848.2 2665000.7 0.23 2500 Nan CS 4122.9 1.5 0.64 2655 1292000.4 0.26 1000 Nan CS 4124.4 4.5 0.62 2542 643500.2 0.28 1000 Nan DS 4128.9 3.5 0.69 2854.3 1774000.4 0.26 1500 Nan DS 4132.4 14.5 0.66 2726 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4146.9 1.5 0.65 2706 1145000.3 0.27 1000 Nan CS 4148.4 12.5 0.64 2641 882100.2 0.27 1000 Nan DS 4160.9 2 0.65 2701.1 1402000.4 0.26 1500 Nan CS 4162.9 9 0.61 2529.6 853600.2 0.27 1000 Nan DS 4171.9 7 0.66 2755 1397000.4 0.26 1500 Nan DS 4178.9 9 0.65 2705 1132000.3 0.27 1500 Nan DS 4187.9 3.5 0.64 2689.8 1688000.4 0.26 1500 Nan DS 4191.4 5 0.64 2684.1 757000.2 0.27 1000 Nan DS 4196.4 2 0.7 2925 1795000.5 0.25 1500 Nan CS 4198.4 10.5 0.62 2602.1 735600.2 0.27 1000 Nan CS 4208.9 3.5 0.65 2724.3 1098000.3 0.27 1000 Nan CS 4212.4 2 0.62 2614 670200.2 0.28 1000 Nan CS 4214.4 5.5 0.66 2787.5 1300000.3 0.26 1000 Nan DS 4219.9 3.5 0.69 2934 1531000.4 0.26 1500 Nan DS 4223.4 3.5 0.64 2701 1193000.3 0.27 1500 Nan DS 4226.9 5.5 0.69 2922.7 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4232.4 10.5 0.64 2712.1 1171000.3 0.27 1000 Nan DS 4242.9 1.5 0.67 2830.5 1376000.4 0.26 1500 Nan DS 4244.4 5 0.62 2641.6 1139000.3 0.27 1500 Nan DS 4249.4 2 0.66 2809 1560000.5 0.26 1500 Nan DS 4251.4 4 0.63 2688 896400.2 0.27 1500 Nan DS 4255.4 2 0.68 2876 1656000.4 0.26 1500 Nan DS 4257.4 10 0.63 2672.5 981000.2 0.27 1500 Nan DS 4267.4 4 0.65 2792.2 1633000.4 0.26 1500 Nan DS 4271.4 4 0.7 2974 1749000.4 0.26 1500 Nan DS 4275.4 9.5 0.66 2803.5 1327000.4 0.26 1500 Nan DS 4284.9 2 0.62 2644.4 781500.2 0.27 1000 Nan DS 4286.9 9.5 0.69 2969.8 1692000.4 0.26 1500 Nan DS 4296.4 2 0.66 2832 1365000.4 0.26 1500 Shale 4298.4 2 0.7 2996.7 2665000.7 0.23 2500 Nan DS 4300.4 2 0.64 2735.7 1088000.3 0.27 1500 Shale 4302.4 2 0.7 2999.5 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4304.4 4 0.67 2863.8 1287000.3 0.26 1500 Shale 4308.4 19.5 0.7 3009.8 2665000.7 0.23 2500 Nan DS 4327.9 2 0.66 2839.8 1356000.3 0.26 1500 Shale 4329.9 2 0.7 3018.6 2665000.7 0.23 2500 Nan DS 4331.9 8 0.66 2874.7 1373000.4 0.26 1500 Nan DS 4339.9 8 0.65 2810.5 1558000.4 0.26 1500 Shale 4347.9 20 0.7 3042 2665000.7 0.23 2500 Name: Stage 11 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 10 PAD 45 YF126ST 17850 425 9.44 2 1 PPA 45 YF126ST 7640.7 190 CarboLite 16/20 + SG 1 7640.7 4.22 3 2 PPA 45 YF126ST 8100.8 210 CarboLite 16/20 + SG 2 16201.6 4.67 4 4 PPA 45 YF126ST 8025.2 225 CarboLite 16/20 + SG 4 32100.8 5 5 6 PPA 45 YF126ST 7462.7 225 CarboLite 16/20 + SG 6 44776.2 5 NDB-040 (Attachment K) Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 6 8 PPA 45 YF126ST 6974 225 CarboLite 16/20 + SG 8 55792 5 7 10 PPA 45 YF126ST 6109 210 CarboLite 16/20 + SG 10 61090 4.67 8 12 PPA 45 YF126ST 5070 185 CarboLite 16/20 + SG 12 60840 4.11 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.55 22.43 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67232.4 278441.3 1894.99 42.11 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max SurfacePressure (psi) Max Height (ft) Stage 11 7141.4 250.77 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4064.84 4315.61 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 11 859.45 210.24 0.42 NDB-040 (Attachment K) Stage 12 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 12 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6312.8 psi Zoneset name: Stage 12 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4066.11 10 0.72 2940.5 1461000.3 0.22 1000 Shale 4076.12 15 0.69 2838.1 1762000.5 0.22 1000 Nanushuk 3 SS 4091.11 15.3 0.68 2778.92 1898000.5 0.22 1000 Top Nan CS 4106.4 19.5 0.63 2593.13 900400.2 0.27 1000 Nan SS 4125.89 2 0.69 2851.59 2665000.7 0.23 2500 Nan CS 4127.89 1.5 0.64 2658.25 1292000.4 0.26 1000 Nan CS 4129.4 4.5 0.62 2545.12 643500.2 0.28 1000 Nan DS 4133.89 3.5 0.69 2857.82 1774000.4 0.26 1500 Nan DS 4137.4 14.5 0.66 2729.32 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4151.9 1.5 0.65 2709.3 1145000.3 0.27 1000 Nan CS 4153.41 12.5 0.64 2644.18 882100.2 0.27 1000 Nan DS 4165.91 2 0.65 2704.37 1402000.4 0.26 1500 Nan CS 4167.91 9 0.61 2532.65 853600.2 0.27 1000 Nan DS 4176.9 7 0.66 2758.33 1397000.4 0.26 1500 Nan DS 4183.89 9 0.65 2708.29 1132000.3 0.27 1500 Nan DS 4192.91 3.5 0.64 2693.06 1688000.4 0.26 1500 Nan DS 4196.39 5 0.64 2687.26 757000.2 0.27 1000 Nan DS 4201.41 2 0.7 2928.46 1795000.5 0.25 1500 Nan CS 4203.41 10.5 0.62 2605.17 735600.2 0.27 1000 Nan CS 4213.91 3.5 0.65 2727.58 1098000.3 0.27 1000 Nan CS 4217.39 2 0.62 2617.06 670200.2 0.28 1000 Nan CS 4219.39 5.5 0.66 2790.82 1300000.3 0.26 1000 Nan DS 4224.9 3.5 0.69 2937.45 1531000.4 0.26 1500 Nan DS 4228.41 3.5 0.64 2704.23 1193000.3 0.27 1500 Nan DS 4231.89 5.5 0.69 2926.14 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4237.4 10.5 0.64 2715.25 1171000.3 0.27 1000 Nan DS 4247.9 1.5 0.67 2833.89 1376000.4 0.26 1500 Nan DS 4249.41 5 0.62 2644.76 1139000.3 0.27 1500 Nan DS 4254.4 2 0.66 2812.28 1560000.5 0.26 1500 Nan DS 4256.4 4 0.63 2691.18 896400.2 0.27 1500 Nan DS 4260.4 2 0.68 2879.43 1656000.4 0.26 1500 Nan DS 4262.4 10 0.63 2675.66 981000.2 0.27 1500 Nan DS 4272.41 4 0.65 2795.46 1633000.4 0.26 1500 Nan DS 4276.41 4 0.7 2977.48 1749000.4 0.26 1500 Nan DS 4280.41 9.5 0.66 2806.77 1327000.4 0.26 1500 Nan DS 4289.9 2 0.62 2647.52 781500.2 0.27 1000 Nan DS 4291.9 9.5 0.69 2973.27 1692000.4 0.26 1500 Nan DS 4301.41 2 0.66 2835.34 1365000.4 0.26 1500 Shale 4303.41 2 0.7 3000.25 2665000.7 0.23 2500 Nan DS 4305.41 2 0.64 2738.89 1088000.3 0.27 1500 Shale 4307.41 2 0.7 3003.01 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4309.42 4 0.67 2867.11 1287000.3 0.26 1500 Shale 4313.39 19.5 0.7 3013.3 2665000.7 0.23 2500 Nan DS 4332.91 2 0.66 2843.03 1356000.3 0.26 1500 Shale 4334.91 2 0.7 3022.15 2665000.7 0.23 2500 Nan DS 4336.91 8 0.66 2877.98 1373000.4 0.26 1500 Nan DS 4344.91 8 0.65 2813.73 1558000.4 0.26 1500 Shale 4352.89 20 0.7 3045.5 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 12 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 10 PAD 45 YF126ST 17850 425 9.44 2 1 PPA 45 YF126ST 9048.5 225 CarboLite 16/20 + SG 1 9048.5 5 3 2 PPA 45 YF126ST 9258.2 240 CarboLite 16/20 + SG 2 18516.4 5.33 4 4 PPA 45 YF126ST 9273.7 260 CarboLite 16/20 + SG 4 37094.8 5.78 5 6 PPA 45 YF126ST 8623.8 260 CarboLite 16/20 + SG 6 51742.8 5.78 6 8 PPA 45 YF126ST 6508.9 210 CarboLite 16/20 + SG 8 52071.2 4.67 7 8 PPA 45 YF126ST 1244.6 40 CarboLite 12/18 8 9956.8 0.89 8 10 PPA 45 YF126ST 6136.5 210 CarboLite 12/18 10 61365 4.67 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.27 22.73 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67944.2 239795.5 1870 41.56 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 12 6312.8 251.2 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4070.2 4321.4 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 12 879 213.13 0.28 NDB-040 (Attachment K) Stage 13 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 13 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6126.9 psi Zoneset name: Stage 13 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4073.1 10 0.72 2945.57 1461000.3 0.22 1000 Shale 4083.1 15 0.69 2842.88 1762000.5 0.22 1000 Nanushuk 3 SS 4098.1 15.3 0.68 2783.71 1898000.5 0.22 1000 Top Nan CS 4113.39 19.5 0.63 2597.63 900400.2 0.27 1000 Nan SS 4132.91 2 0.69 2856.52 2665000.7 0.23 2500 Nan CS 4134.91 1.5 0.64 2662.75 1292000.4 0.26 1000 Nan CS 4136.38 4.5 0.62 2549.33 643500.2 0.28 1000 Nan DS 4140.91 3.5 0.69 2862.61 1774000.4 0.26 1500 Nan DS 4144.39 14.5 0.66 2733.96 1388000.3 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4158.89 1.5 0.65 2713.8 1145000.3 0.27 1000 Nan CS 4160.4 12.5 0.64 2648.68 882100.2 0.27 1000 Nan DS 4172.9 2 0.65 2708.87 1402000.4 0.26 1500 Nan CS 4174.9 9 0.61 2536.86 853600.2 0.27 1000 Nan DS 4183.89 7 0.66 2762.97 1397000.4 0.26 1500 Nan DS 4190.91 9 0.65 2712.79 1132000.3 0.27 1500 Nan DS 4199.9 3.5 0.64 2697.56 1688000.4 0.26 1500 Nan DS 4203.41 5 0.64 2691.76 757000.2 0.27 1000 Nan DS 4208.4 2 0.7 2933.39 1795000.5 0.25 1500 Nan CS 4210.4 10.5 0.62 2609.52 735600.2 0.27 1000 Nan CS 4220.9 3.5 0.65 2732.08 1098000.3 0.27 1000 Nan CS 4224.41 2 0.62 2621.41 670200.2 0.28 1000 Nan CS 4226.41 5.5 0.66 2795.46 1300000.3 0.26 1000 Nan DS 4231.89 3.5 0.69 2942.38 1531000.4 0.26 1500 Nan DS 4235.4 3.5 0.64 2708.72 1193000.3 0.27 1500 Nan DS 4238.91 5.5 0.69 2930.92 1416000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4244.39 10.5 0.64 2719.75 1171000.3 0.27 1000 Nan DS 4254.89 1.5 0.67 2838.53 1376000.4 0.26 1500 Nan DS 4256.4 5 0.62 2649.11 1139000.3 0.27 1500 Nan DS 4261.38 2 0.66 2816.92 1560000.5 0.26 1500 Nan DS 4263.39 4 0.63 2695.53 896400.2 0.27 1500 Nan DS 4267.39 2 0.68 2884.08 1656000.4 0.26 1500 Nan DS 4269.39 10 0.63 2680.01 981000.2 0.27 1500 Nan DS 4279.4 4 0.65 2800.1 1633000.4 0.26 1500 Nan DS 4283.4 4 0.7 2982.41 1749000.4 0.26 1500 Nan DS 4287.4 9.5 0.66 2811.41 1327000.4 0.26 1500 Nan DS 4296.92 2 0.62 2651.87 781500.2 0.27 1000 Nan DS 4298.88 9.5 0.69 2978.06 1692000.4 0.26 1500 Nan DS 4308.4 2 0.66 2839.84 1365000.4 0.26 1500 Shale 4310.4 2 0.7 3005.04 2665000.7 0.23 2500 Nan DS 4312.4 2 0.64 2743.39 1088000.3 0.27 1500 Shale 4314.4 2 0.7 3007.94 2665000.7 0.23 2500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4316.4 4 0.67 2871.75 1287000.3 0.26 1500 Shale 4320.41 19.5 0.7 3018.24 2665000.7 0.23 2500 Nan DS 4339.9 2 0.66 2847.67 1356000.3 0.26 1500 Shale 4341.9 2 0.7 3026.94 2665000.7 0.23 2500 Nan DS 4343.9 8 0.66 2882.63 1373000.4 0.26 1500 Nan DS 4351.9 8 0.65 2818.23 1558000.4 0.26 1500 Shale 4359.91 20 0.7 3050.43 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 13 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 10 PAD 45 YF126ST 18900 450 10 2 1 PPA 45 YF126ST 10053.8 250 CarboLite 16/20 + SG 1 10053.8 5.56 3 2 PPA 45 YF126ST 10801.2 280 CarboLite 16/20 + SG 2 21602.4 6.22 4 4 PPA 45 YF126ST 9987 280 CarboLite 16/20 + SG 4 39948 6.22 5 6 PPA 45 YF126ST 9287 280 CarboLite 16/20 + SG 6 55722 6.22 6 8 PPA 45 YF126ST 6819 220 CarboLite 16/20 + SG 8 54552 4.89 7 8 PPA 45 YF126ST 1244.7 40 CarboLite 12/18 8 9957.6 0.89 8 10 PPA 45 YF126ST 6428.6 220 CarboLite 12/18 10 64286 4.89 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 25.71 22.28 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 73521.3 256121.8 2020 44.89 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 13 6126.9 252.05 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4076.85 4328.9 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 13 900.15 210.14 0.34 NDB-040 (Attachment K) Stage 14 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 14 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5934.2 psi Zoneset name: Stage 14 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4076.12 10 0.72 2947.75 1461000.3 0.22 1000 Shale 4086.09 15 0.69 2845.06 1762000.5 0.22 1000 Nanushuk 3 SS 4101.12 15.3 0.68 2785.74 1898000.5 0.22 1000 Top Nan CS 4116.4 19.5 0.63 2599.51 900400.2 0.27 1000 Nan SS 4135.89 2 0.69 2858.55 2665000.7 0.23 2500 Nan CS 4137.89 1.5 0.64 2664.63 1292000.4 0.26 1000 Nan CS 4139.4 4.5 0.62 2551.21 643500.2 0.28 1000 Nan DS 4143.9 3.5 0.69 2864.64 1774000.4 0.26 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4147.41 14.5 0.66 2735.85 1388000.3 0.26 1500 Nan CS 4161.91 1.5 0.65 2715.83 1145000.3 0.27 1000 Nan CS 4163.39 12.5 0.64 2650.56 882100.2 0.27 1000 Nan DS 4175.89 2 0.65 2710.76 1402000.4 0.26 1500 Nan CS 4177.89 9 0.61 2538.74 853600.2 0.27 1000 Nan DS 4186.91 7 0.66 2764.85 1397000.4 0.26 1500 Nan DS 4193.9 9 0.65 2714.67 1132000.3 0.27 1500 Nan DS 4202.89 3.5 0.64 2699.44 1688000.4 0.26 1500 Nan DS 4206.4 5 0.64 2693.64 757000.2 0.27 1000 Nan DS 4211.38 2 0.7 2935.42 1795000.5 0.25 1500 Nan CS 4213.39 10.5 0.62 2611.4 735600.2 0.27 1000 Nan CS 4223.88 3.5 0.65 2733.96 1098000.3 0.27 1000 Nan CS 4227.4 2 0.62 2623.3 670200.2 0.28 1000 Nan CS 4229.4 5.5 0.66 2797.49 1300000.3 0.26 1000 Nan DS 4234.91 3.5 0.69 2944.41 1531000.4 0.26 1500 Nan DS 4238.39 3.5 0.64 2710.61 1193000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4241.9 5.5 0.69 2933.1 1416000.4 0.26 1500 Nan CS 4247.41 10.5 0.64 2721.63 1171000.3 0.27 1000 Nan DS 4257.91 1.5 0.67 2840.56 1376000.4 0.26 1500 Nan DS 4259.42 5 0.62 2651 1139000.3 0.27 1500 Nan DS 4264.4 2 0.66 2818.95 1560000.5 0.26 1500 Nan DS 4266.4 4 0.63 2697.41 896400.2 0.27 1500 Nan DS 4270.41 2 0.68 2886.11 1656000.4 0.26 1500 Nan DS 4272.41 10 0.63 2681.89 981000.2 0.27 1500 Nan DS 4282.41 4 0.65 2801.98 1633000.4 0.26 1500 Nan DS 4286.38 4 0.7 2984.44 1749000.4 0.26 1500 Nan DS 4290.39 9.5 0.66 2813.3 1327000.4 0.26 1500 Nan DS 4299.9 2 0.62 2653.61 781500.2 0.27 1000 Nan DS 4301.9 9.5 0.69 2980.24 1692000.4 0.26 1500 Nan DS 4311.38 2 0.66 2841.87 1365000.4 0.26 1500 Shale 4313.39 2 0.7 3007.21 2665000.7 0.23 2500 Nan DS 4315.39 2 0.64 2745.27 1088000.3 0.27 1500 NDB-040 (Attachment K) Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4317.39 2 0.7 3009.97 2665000.7 0.23 2500 Nan DS 4319.39 4 0.67 2873.78 1287000.3 0.26 1500 Shale 4323.39 19.5 0.7 3020.27 2665000.7 0.23 2500 Nan DS 4342.91 2 0.66 2849.7 1356000.3 0.26 1500 Shale 4344.91 2 0.7 3029.11 2665000.7 0.23 2500 Nan DS 4346.92 8 0.66 2884.66 1373000.4 0.26 1500 Nan DS 4354.89 8 0.65 2820.26 1558000.4 0.26 1500 Shale 4362.89 20 0.7 3052.46 2665000.7 0.23 2500 NDB-040 (Attachment K) Name: Stage 14 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 10 PAD 45 YF126ST 16800 400 8.89 2 1 PPA 45 YF126ST 8244.2 205 CarboLite 16/20 + SG 1 8244.2 4.56 3 3 PPA 45 YF126ST 7601.9 205.1 CarboLite 16/20 + SG 3 22805.7 4.56 4 5 PPA 45 YF126ST 9624.2 280 CarboLite 16/20 + SG 5 48121 6.22 5 7 PPA 45 YF126ST 8171.3 255 CarboLite 16/20 + SG 7 57199.1 5.67 6 9 PPA 45 YF126ST 7653.3 255 CarboLite 16/20 + SG 9 68879.7 5.67 7 10 PPA 45 YF126ST 6545.4 224 CarboLite 12/18 10 65454 4.98 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 25.99 21.93 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 64640.3 270703.7 1824.09 40.54 NDB-040 (Attachment K) Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 14 5934.2 248.19 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4081.54 4329.73 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 14 820.93 207.21 0.35 1 Dewhurst, Andrew D (OGC) From:Leahy, Scott (Scott) <Scott.Leahy@santos.com> Sent:Tuesday, 11 November, 2025 08:28 To:Dewhurst, Andrew D (OGC) Cc:Wallace, Chris D (OGC); Atherton, Michaela (Michaela); Senden, Robert (Ty); Miller, Nicklaus (Nick) Subject:RE: Pikka NDB-040 Frac Sundry (325-680) Attachments:Aquifer Salinity Documentation.pdf Andy, Please view the attachment for documentation showing a salinity analysis for 3 wells in the Pikka unit. This .pdf attachment is from a section of the approved Sundry from NDBi-043. Steve had questioned that point as well. Hope this helps. Regards, Scott Leahy Completions Specialist Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Ave Anchorage, Alaska 99501 m: +1 (907) 330-4595 Scott.Leahy@santos.com https://www.santos.com/ From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, November 10, 2025 4:11 PM To: Leahy, Scott (Scott) <Scott.Leahy@santos.com> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: ![EXT]: Pikka NDB-040 Frac Sundry (325-680) Scott, I received the survey and log data. I have one other question. In section 3, it is stated that there are no known underground sources of drinking water (typically found down to 400 depth). Would you conrm that there are no freshwater aquifers as dened in 20 AAC 25.990(27) as having a TDS of less than 10,000 mg/l? Im asking specically for any aquifers below permafrost. I believe our own calculations show them all above 10,000 ppm, but just want to conrm. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Wednesday, 5 November, 2025 14:08 To:'scott.leahy@santos.com' Cc:Wallace, Chris D (OGC); Guhl, Meredith D (OGC); McLellan, Bryan J (OGC) Subject:Pikka NDB-040 Frac Sundry (325-680): Question Scott, To help us with the review of the Pikka NDB-040 frac sundry, would you please provide the following: Directional survey (.txt, .xlsx, or equivalent) LWD logs (.las) Any relevant formation tops Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-040 (PTD No. 225-084; Sundry No. 325-680) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 November 10, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 05NOV25 (a)(2) Plat Provided with application. A.Dewhurst 05NOV25 (a)(2)(A) Well location Provided with application. A.Dewhurst 05NOV25 (a)(2)(B) Each water well within ½ mile None: There are no wells used for drinking water purposes known to lie within ½ mile of the surface location of Pikka NDB-040. There are no subsurface water rights or temporary subsurface water rights within 10 miles of the surface location of Pikka NDB-040. A.Dewhurst 05NOV25 (a)(2)(C) Identify all well types within ½ mile Provided with application. Santos has identified 6 wells withing ½-mile. A.Dewhurst 05NOV25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the Pikka Unit per salinity calculations provided by the operator on Aug. 21, 2023 as part of their Sundry Application to hydraulically fracture nearby well Pikka NDB-024 (see AOGCCs Well History File 223-076, p. 101-107 of Sundry Application 323-591). Pickett Plot well-log analyses were performed on three wells within the unit that have wireline log coverage from surface through the fracturing interval: Colville River 1, Till 1, and Pikka DW-02. Estimated salinity values for clean, porous 100% water-saturated sands beneath the base of the permafrost layer in these three wells are: Colville River 1 (PTD 192-153) ~20,000 mg/l between 1,400 and 2,000 MD (-1,354 to 1,954' TVDSS; base of permafrost 1,350 MD (-1,313 TVDSS)); Till 1 (PTD 193-004) 16,700 to ~23,000 mg/l between 1,400 and 1,500 MD (-1,463 to -1,363 TVDSS; base of permafrost 1,350 MD (-1,305 TVDSS)); and DW-02 (PTD 223-039) ~21,500 mg/l between 1,550 and 1,650 MD (-A.Dewhurst 05NOV25 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-040 (PTD No. 225-084; Sundry No. 325-680) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 November 10, 2025 1,408 to -1,486 TVDSS; base of permafrost ~1,170 MD (~-1,080 TVDSS)). (a)(4) Baseline water sampling plan None required. A.Dewhurst 05NOV25 (a)(5) Casing and cementing information Provided with application. Schematic attached, As-Built. Cement information on diagram. CDW 11/05/2025 (a)(6) Casing and cementing operation assessment 13-3/8 surface casing cemented to surface. 9-5/8 intermediate liner set at 9995 ft and cemented in 2 stages. First stage at shoe of 9995 ft with cement pumped to achieve 1000 ft MD above shoe coverage. 2nd stage at CFLEX collar of 6377 ft with cement circulated off liner top. 7 liner tied back to surface. TOC 12486 ft USIT/CBL shows partial cement from 11667 ft and good cement from 12486 ft 4.5 tubing tied in to 4.5 uncemented liner.will be anchored with a retrievable packer set at approx. 14715 ft with perforations planned for 15296-22613 ft. CDW 11/05/2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) A.Dewhurst 05NOV25 (a)(6)( B) Each hydrocarbon zone is isolated Yes. The Tuluvak hydrocarbon zone is adequately isolated by the 2nd stage of the 9-5/8 intermediate liner cement job. The multiple Nanushuk hydrocarbon zones within the Nanushuk Oil Pool are isolated by the 7 intermediate 2 liner cement job. A.Dewhurst 05NOV25/ Drlg Eng 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-040 (PTD No. 225-084; Sundry No. 325-680) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 November 10, 2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 4300 psi MITIA planned, 5500 psi MITT plan. CDW 11/05/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi frac tree max. frac. Pressure modelled as 7313 psi. MAWP 8800 psi. GORV 8500 psi., lines test 9200 psi. CDW 11/05/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper Confining Zones: Over 500 true vertical thickness (TVT) of claystone, shale and volcanic tuff assigned to the Seabee Formation having an estimated fracture gradient of 13.7 ppg EMW (0.71 psi/ft). Fracturing Zone: Perforated zone lies within a subdivision of the Nanushuk Formation which is comprised of highly laminated fine-grained sandstones, silts, and shales. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm which is about 950 TVT in this area and has an estimated fracture gradient of 11.7 ppg EMW (0.61 psi/ft). Lower Confining Zones: About 1,200 TVT of Lower Torok (Hue) shales and interbedded siltstones with an estimated fracture gradient of 13.3 ppg EMW (0.69 psi/ft). A.Dewhurst 10NOV25 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Provided with application. AOGCC evaluated all 6 wells that transect the confining zones within the Pikka NDB-040 Area of Review and found it highly unlikely that any of these wells will interfere with fracturing fluids due to cement-isolation and/or separation distance or direction. NDB-50 is 112 ft above NDB-40. Model max frac height is 239 to 252 ft. A.Dewhurst 05NOV25/ CDW 11/05/2025 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic None. The operator has not identified any faults or fracture zones through seismic or well data within a ½-mile radius of Pikka NDB-040. It is unlikely that any faults will interfere with containment of the injected fracturing fluids; however, if A.Dewhurst 05NOV25 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-040 (PTD No. 225-084; Sundry No. 325-680) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 November 10, 2025 fracturing fluid within ½ mile of the proposed wellbore trajectory there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. (a)(12) Proposed program for fracturing operation Provided with application. CDW 11/05/2025 (a)(12)(A) Estimated volume Provided with application. 27K bbl total dirty vol. 3.45Million lb total proppant CDW 11/05/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 11/05/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. SLB, Tracerco, Patina disclosure provided. Proprietary chemicals on file at AOGCC. CDW 11/05/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 11/05/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7313 psi. Max. 8800 psi allowable treating pressure. GORV 8500 psi. With 3800 psi back pressure IA (IA popoff set 4100psi), max tubing differential should be 5000 psi. CDW 11/05/2025 (a)(12)(F) Fractures height, length, MD and TVD to top, description of fracturing model Provided with application. The maximum anticipated half-length of the induced fractures is 521 according to the Operators computer simulation. Computer simulation indicates the maximum anticipated height of the induced fractures will be 252, so it is unlikely that induced fractures will penetrate into the overlying confining zone. Detailed depths are provided in the application. A.Dewhurst 05NOV25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 11/05/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3800 psi back pressure, plan to test to 4300 psi, popoff set as 4100 psi CDW 11/05/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-040 (PTD No. 225-084; Sundry No. 325-680) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 November 10, 2025 (c) Fracturing string (c)(1) Packer >100 below TOC of production or intermediate casing 4.5 tubing will be anchored with a retrievable packer set at approx. 14715 ft with perforations planned for 15296-22613 ft. 7 TOC 12486 ft USIT/CBL shows partial cement from 11667 ft and good cement from 12486 ft so conservatively good cement at area of interest so no cement concerns. 13-3/8 surface casing cemented to surface. CDW 11/05/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 5500 psi. Max pressure differential is estimated as 5000 psi (8800 with 3800 psi backpressure) so test of 5500 psi satisfies 110% CDW 11/05/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9200 psi line pressure test, with max. global kickout 8500 psi. IA PRV set as 4100 psi. CDW 11/05/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 11/05/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 4100 psi. Surface annulus open. Frac pressures continuously monitored. CDW 11/05/2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 11/05/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-040 (PTD No. 225-084; Sundry No. 325-680) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 November 10, 2025 (j) Post-frac water sampling plan Not required (see Section (a)(3), above). A.Dewhurst 05NOV25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 05NOV25 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. From:McLellan, Bryan J (OGC) To:Staudinger, Mark (Mark) Subject:RE: NDB-040 Sundry Application Date:Wednesday, October 29, 2025 5:05:00 PM Attachments:image005.png Thanks for the update. The change is approved. Oil Search will need to test the rams after any ram swap. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Wednesday, October 29, 2025 4:31 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: NDB-040 Sundry Application Hey Bryan, As discussed, due to some issues with the Lower Completion and timing, we are going to change the order of operations slightly from the proposal in the Sundry. The overall well design will not change. Essentially, we are going to run the 7” x 9-5/8” tieback prior to the Lower Completion, which means that we’ll need to have an additional Upper VBR Ram swap to 3-1/2” x 5” prior to running the Lower Completion (since we now will need to run Lower Completion on 4” DP). I just wanted to keep you informed of this slight change in our order of operations. Thanks, Mark Mark Staudinger Senior Drilling Engineer CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 21, 2025 3:58 PM To: Atherton, Michaela (Michaela) <Michaela.Atherton@santos.com>; Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Cc: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: ![EXT]: RE: NDB-040 Sundry Application Mark & Michaela Verbal approval of the attached sundry application is granted. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Atherton, Michaela (Michaela) <Michaela.Atherton@santos.com> Sent: Tuesday, October 21, 2025 3:01 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDB-040 Sundry Application Hello, Please see attached Sundry application for NDB-040. @McLellan, Bryan J (OGC), Mark is requesting a verbal approval to proceed with the Sundry request. Thank you, Michaela Atherton Technical Assistant– Drilling & Completions t: (907-375-4678) | e: (michaela.atherton@santos.com) Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?Pikka / NDB-040 Yes No 9. Property Designation (Lease Number): 10. Field: Pikka Nanushuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 14,926' 4,115' 1,492 Casing Collapse Structural Conductor Surface 2,260 Intermediate1 4,750 Intermediate2 5,410 Production Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Mark Staudinger Contact Email:mark.staudinger@santos.com Contact Phone: 520-273-6643 Authorized Title: Senior Drilling Engineer Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 391445, 393023, 393022, 392977, 392958 225-084 601 W 5th Avenue, Anchorage, AK 99501-6301 50-103-20924-00-00 Oil Search Alaska, LLC Length Size Proposed Pools: TVD Burst 7,240 MD 6,870 5,020 128' 2,389' 3,282' 128' 3,058' 4,114'7" 20"x34" 13-3/8" 128' 9-5/8"7,128' 3,011' 14,921' Perforation Depth MD (ft): 9,995' 5,071' m n s 2 66 t _ c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov g g p October 21, 2025 325-658 By Grace Christianson at 9:13 am, Oct 22, 2025 Yes 10/21/25 Bryan McLellan BJM 10/22/25 A.Dewhurst 22OCT25 DSR-10/22/25 10-407 Conditions of approval on original PTD still apply. 10/23/25 Page 1 of 1 21 October 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Sundry for Changes to Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-040 (PTD 225-084) Dear Sir/Madam, Oil Search (Alaska), LLC hereby applies for a Sundry for changes to approved Permit to Drill 225-084 for well NDB-040. The 8-1/2 x 9-7/8 intermediate 2 hole was drilled to a depth of 14,296 MD (top-set Nanushuk 3.2 reservoir). 7 liner was successfully run and cemented to a depth of 14,921 MD. During operations for polishing the Seal Bore Receptable (SBE) at the top of the 9-5/8 liner (2,867 MD), the polish mill was unable to fully enter the SBE. The team suspected a lip at the liner top preventing the upper polish mill from entering, so a string mill was run to dress the top of the SBE. However, after SBE dressing operations, the polish mill assembly is still unable to fully enter the SBE. The team suspects that there is a dimensional issue with the SBE, which will prevent seals from entering, thus the 9-5/8 tieback is unable to be run as per plan. Plan forward will be to run a 9-5/8 temporary tieback with no seals, allowing for the production section to be drilled, providing both hole cleaning benefits and protection for running 4-1/2 lower completion. The 6-1/8 production hole lateral will be drilled to TD and completed as originally planned (stimulated injector with 4-1/2 liner with frac sleeves and isolation packers). Following installation of the 4-1/2 liner, the 9-5/8 tieback will be removed. A 9-5/8 x 7 tieback will then be installed, which ties into the top of the 7 liner top packer. The tieback will be crossed over to 9-5/8 above the 9-5/8 liner top packer. The 4-1/2 upper completion will be installed as originally planned. If there are any questions and/or additional information desired, please contact me at (520) 273-6643 or mark.staudinger@santos.com. Respectfully, Mark Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-403 Respectfully, Mark Staudinger Sundry to Permit to Drill NDB-040 Well PTD 225-084 Changes to approved Permit to Drill (PTD 225-084) are in red text below 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 42 20x34 215# X-52 Welded 80 Surface 128 / 128 16 13-3/8 68# L-80 TXP BTC 3,055 Surface 3,055 / 2,394 12-1/4 9-5/8 47# L-80 HYD 563 7,095 2,905 10,000 /3,282 8-1/2 x 9-7/87 26 L-80 HYD 563 5,066 9,850 14,916 / 4,113 Tie Back 9-5/8 47# L-80 HYD 563 2,800 Surface 2,800 / 2,309 Tie Back 7 26# L-80 HYD 563 7,050 2,800 9,850 / 3,264 6-1/8 4-1/2 12.6# P-110S HYD 563 8,118 14,766 22,884 / 4,098 Tubing 4-1/2 12.6# P-110S HYD 563 14,766 Surface 14,766 / 4,080 Please refer to Attachment 6: Cement Summary for further details. 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to NDB-040 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed NDB-040 Drilling Program 1. Drill 20 conductor to ~128 MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools over the 20 conductor. 4. Pick up 5-7/8 drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16 motor BHA with MWD and LWD tools. 5. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 6. Run 13-3/8 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 7. Cement 13-3/8 casing as per cement program. Verify cement returns to surface. 8. NU casing head and spacer spool. NU BOPE with Rotating Control Device (RCD). BOP configured from top to bottom: annular preventor, 4-1/2 x 7 VBR, blind/shear, mud cross, 9-5/8 Fixed Rams. Test rams to 5000 psi high (initial test only 3600 psi for subsequent tests) and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 48hrs notice for witnessing BOP test. 9. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 10. Make up 12-1/4 RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to MOBM. 11. Drill out shoe track and 20 - 50 of new formation. Perform FIT / LOT. 12. Directionally drill 12-1/4 intermediate hole section #1 to TD. Perform wiper trips as required. Circulate and condition hole to run liner. POOH. 13. RU and run 9-5/8 intermediate liner #1 as per casing tally then RIH on 5-7/8 DP / HWDP to TD. Circulate and condition mud prior to commencing cement job. 14. Set liner hanger and release running tool. Cement 9-5/8 liner with 1st stage cement job as per cement program. Monitor returns during displacement until plug bump. 15. Un-sting from liner hanger and POOH and LD liner running tools. 16. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Pump secondary cement job, set liner top packer, and circulate cement to surface. POOH and lay down 5- 7/8 drillpipe and liner running tool. 17. Pressure test casing 13-3/8 casing and 9-5/8 liner to 2600 psi for 30 min. 18. Make up 8-1/2 RSS BHA with MWD and LWD tools. RIH on 5 drillpipe, clean out to top of float equipment and drill out the shoe track. 19. Drill out the 9-5/8 shoe and 20 - 50 of new formation. Perform FIT / LOT. 20. Install the MPD bearing assembly and adjust mud weight as required for ECD management with MPD. 21. Directionally drill 8-1/2 x 9-7/8 intermediate hole section #2 to TD utilizing MPD. Perform wiper trips as required. 22. Circulate and condition hole to run liner. Displace weighted trip fluid as required and POOH. 23. Run cleanout/string mill assembly to dress the 9-5/8 CFLEX tool. 24. RU and run 7 intermediate liner #2 as per casing tally then RIH on 5 DP / HWDP to TD. Circulate and condition mud prior to commencing cement job. 25. Set liner hanger and release running tool. Cement 7 liner as per cement program. Monitor returns during displacement until plug bump. 26. Set liner top packer, un-sting from liner hanger, POOH and LD liner running tools. 27. Pressure test the 13-3/8 casing x 9-5/8 liner x 7 liner to 2600 psi for 30 min. 28. RIH with temporary 9-5/8 tieback string (no seals). 29. Make up 6-1/8 RSS BHA with MWD and LWD tools. RIH on tapered string with 4 x 5 drillpipe. 30. RIH to top of the float equipment logging 7 liner cement with Sonic LWD tool on the trip in. 31. Displace well to MOBM at the required mud weight for MPD while drilling out the shoe track. 32. Circulate casing clean, install the MPD bearing assembly and test MPD surface equipment as required. 33. Drill 20 - 50 of new formation. Perform FIT / LOT. 34. Directionally drill 6-1/8 production hole section to TD using MPD. Perform wiper trips as required. 35. Circulate and condition hole to run liner. Displace weighted trip fluid as required and POOH. 36. RU and run 4-1/2 production liner as per tally then RIH on tapered 4 x 5 DP to TD. 37. Drop 1.125 ball during circulation to close WIV and circulate down to WIV collar. 38. Close WIV collar and liner hanger/top packer. 39. Set and pressure test the 9-5/8 x 7 x 4-1/2 IA to liner top packer to 2,600 psi for 10 min. Release the running tool. 40. POOH and LD liner running tool. 41. RIH with polish mill assembly for cleanout of the 7 liner top PBR. 42. Pull 9-5/8 temporary Tieback and lay down. 43. Change upper BOP rams from 3-1/2 x 5-1/2 VBRs to 4-1/2 x 7 VBRs. Test rams to 3600 psi high per AOGCC regulations. Provide AOGCC 48 hrs notice for witnessing BOP test. 44. Run 9-5/8 x 7 Tieback, placing the 9-5/8 x7 crossover ~50 MD above the 9-5/8 liner top. Freeze protect the 13-3/8 x 9-5/8 annulus with diesel and land tieback. 45. Pressure test the 13-3/8 x 9-5/8 x 7 annulus to 2600 psi for 30 min. 46. Pressure test the 9-5/8 tieback and 7 liner / tieback to 3500 psi for 30 min. 47. RU and run 4-1/2 upper completion and downhole jewelry with TEC wire. Space out seals. 48. Circulate 9.2ppg NaCl Brine with corrosion inhibitor and biocide. Land tubing hanger. 49. Pressure test tubing to 3,500 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 50. Reverse circulate freeze protect and U-Tube. 51. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. 52. Secure well and prepare for rig move. Attachment 8: Well Schematic Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Mark Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 601 W 5th Avenue Anchorage, AK, 99501 Re: Pikka Field, Nanushuk Oil Pool, NDBi-040 Oil Search Alaska, LLC Permit to Drill Number: 225-084 Surface Location: 2323’ FSL, 1996’ FWL, Sec 4, T11N, R6E, UM Bottomhole Location: 4917’ FSL, 3459’ FEL, Sec 1, T11N, R5E, UM Dear Mr. Staudinger: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. Proposed dry ditch sample interval from Attachment 9 accepted with modification of Ivishak (not to exceed 30'). This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, *UHJRU\ &.:LOVRQ Commissioner DATED this 2QG day of August 2025. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.22 09:23:15 -08'00' 08/22/25 50-103-20924-00-00 1492 psi. -bjm See attached conditions of approval. 4172 TS 8/21/25 1909 225-084 1891 psi -bjm DSR-8/19/25BJM 8/21/25JLC 8/21/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.22 09:22:44 -08'00' 08/22/25 08/22/25 RBDMS JSB 082725 NDB-040 (PTD 225-084) Permit to Drill CondiƟons of Approval 1. Diverter variance request is approved as per 25 AAC 20.036(h)(2) on the condiƟon that the surface hole may be drilled no deeper than 250 Ō below the MCU marker to maintain 100’ TVD standoī from the gas-bearing Tuluvak sand. 2. IniƟal BOP test to 5000 psi. Subsequent BOP test to 3600 psi. All annular tests to 3000 psi. 3. Variance to 20 AAC 25.035(e)(10)(A) is condiƟonally approved to allow 21-day BOP test interval. See condiƟons of approval in Docket OTH-25-010 leƩer in AƩachment 12 of this PTD applicaƟon. 4. LOT/FIT results to be submiƩed to AOGCC within 48 hours of obtaining the data. 5. If MPD will be used, Oil Search must maintain mud density in excess of the highest anƟcipated reservoir EMW. 6. NoƟfy AOGCC if cement jobs do not go according to plan or if job parameters are not as expected (losses occur, unexpected liŌ pressures occur, cement is not circulated oī the top of the intermediate liner, etc.). Cement to be logged if job does not go according to plan, with possible excepƟons for Įrst stage of 9-5/8” Intermediate #1 casing cement. 7. Variance from pool rules granted to isolate signiĮcant hydrocarbon zone of Upper Tuluvak above TS790 horizon as proposed in secƟon 15. 8. Variance to 20 AAC 25.030(d)(5) for 2-stage intermediate casing cement operaƟon and gap in cement coverage is approved, with stage collar placement as follows (reference secƟon 15 in PTD applicaƟon): a. Stage collar must be placed no shallower than 50' MD below the base of the Upper Tuluvak as de Įned by the TS790 horizon. b. Submit 12-1/4" OH logs to AOGCC as soon as pracƟcal aŌer TD of hole secƟon. The TS790 marker is well-established in the area of NDB pad and therefore Oil Search does not need to seek AOGCC approval of their pick of the TS790 before running 9-5/8” casing. 9. Variance for 9-5/8” Intermediate primary cement of only 100’ TVD (1000’ MD) above shoe is approved as described in secƟon 15 of the PTD. 10. Variance of 7” Intermediate 2 cement of 200' TVD above top of Nanushuk pool is approved. The cement volume should be planned for 200’ TVD above the top of the Nanushuk pool, however a 100’ TVD above the pool result will be accepted. The 7” liner cement quality and height must be veriĮed with a log. 11. The LWD-Sonic log will only be accepted for cement evaluaƟon when the following condiƟons are met: a. Oilsearch to provide a wriƩen log evaluaƟon/interpretaƟon to the AOGCC along with the log as soon as they become available. The evaluaƟon is to indicate the intervals of competent cement that Oilsearch is using to meet the objecƟve requirements for annular isolaƟon and reservoir isolaƟon, and to indicate the locaƟon of conĮning zones, hydrocarbon-bearing zones, overpressured zones and fresh water, if present. Providing the log without an evaluaƟon/interpretaƟon is not acceptable. b. LWD sonic logs must show free pipe and Top of Cement. The log must be run across the target zones and at a depth to ensure the free pipe above the TOC is captured as well as the TOC. If the logged interval does not capture the TOC and free pipe above it, it will need to be re-run, unless the cement was planned to cover the enƟre length of liner or casing. c. Oilsearch will provide a cement job summary report and evaluaƟon along with the cement log and evaluaƟon to the AOGCC when they become available. d. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or addiƟonal logging may be required. Recommend approving diverter variance - T.Starns 8/20/25 Recommend approving variance. TS 8/21/25 Verified cement calcs. -bjm Verified cement calcs. -bjm Verified cement calcs. -bjm Verified cement calcs. -bjm Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PIKKA NDB-040 225-084 PIKKA NANUSHUK OIL WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDB-040Initial Class/TypeDEV / PENDGeoArea890Unit11580On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250840Field & Pool:PIKKA, NANUSHUK OIL - 600100NA1Permit fee attachedYesADL392984, ADL391445, ADL393023, ADL393022,ADL392977, ADL3929582Lease number appropriateYes3Unique well name and numberYesPIKKA, NANUSHUK OIL - 600100 - governed by CO 8074Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18Conductor string providedYes19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgYes2-stage intermediate 1 casing21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedNoDiverter waiver approved27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYes30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S measures not required; None anticipated based on nearby wells35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure range is 0.374 to 0.525 psi/ft (7.2 to 10.1 EMW). Operator's planned mud program36Data presented on potential overpressure zonesNAappears sufficient to control anticipated pressures and maintain wellbore stability37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate8/21/2025ApprBJMDate8/21/2025ApprTCSDate8/21/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/21/2025